RATE CONTROL SEQUENCE FOR DIVERSION TREATMENT

Info

Publication number: 20210148221
Type: Application
Filed: Nov 18, 2019
Publication Date: May 20, 2021
Applicant: HALLIBURTON ENERGY SERVICES, INC. (Houston, TX)
Inventors: Ronald Glen DUSTERHOFT (Katy, TX), Stanley V. STEPHENSON (Duncan, OK), Tim Holiman HUNTER (Duncan, OK), Joshua Lane CAMP (Friendswood, TX)
Application Number: 16/687,421

Abstract

A flow rate control sequence for modulating the flow rate at the surface, so as to increase and/or reduce the rate of flow at specific times and increments so that the flow rate of the diverter material downhole is correspondingly reduced or increased such that it enters dominant fractures and avoids entry of marginal fractures. To achieve this, a diversion plan may be developed involving a plurality of planning stages. These stages may include a first overall planning stage, a second downhole planning stage taking into account downhole rate schedule, and the third surface planning stage taking into account parameters at the surface which may impact a diversion plan. Each of these planning stages may be updated or revised based on the results and constraints of other planning stages

Description

Description

TECHNICAL FIELD

The present disclosure relates to stimulation of wellbores, and in particular to fracturing and diversion processes.

BACKGROUND

Oil and gas operations involve accessing underground hydrocarbon reservoirs contained within subterranean formations. As part of ordinary operations, drilling is conducted to form a borehole in order to access desired underground hydrocarbon reservoirs. In recent times, wellbores are often drilled to include a lateral or horizontal section as well vertical section. After drilling operations are completed the wellbore is stimulated in order to produce or enhance production of hydrocarbons. Stimulation processes include hydraulic fracturing.

Fracturing of a wellbore is generally carried out in stages and often begins at the end of a wellbore furthest from the surface, often called the toe in horizontal wellbores. A perforation gun is inserted into the wellbore to a desired location and activated to form perforations in the surface of the borehole (and casing if the borehole is cased) which extend into the formation. Several fractures are often grouped close together, with such groupings often referred to as clusters. A perforation gun may form several clusters of fractures in the wellbore for each area or zone along the length of the wellbore.

After forming one or more perforations, the perforation gun is then withdrawn toward the surface. Fracturing fluid is then pumped from the surface into the wellbore to extend one or more of the initial fractures formed by the perforation gun. The pressure of the fracturing fluid is sufficient to cause the fractures formed by the perforation gun to propagate and expand. After fracturing is completed for a particular zone along the wellbore, a plug is set isolating that zone. The perforation gun is then again inserted to perforate the next area or zone along the wellbore, which is then also subject to fracturing by a fracturing fluid, and then also plugged. This process is repeated until the desired length of the wellbore has been fractured.

In practice, one or more of the fractures formed by the gun and hydraulic fracturing form different types of fractures, or clusters of fractures, with some being dominant and some marginal. Dominant fractures are larger size and receive fluid from the wellbore at a faster rate as compared to marginal fractures. One reason for this is that the formation rock along the length of a wellbore is not homogeneous. Some areas of rock along the wellbore may be stronger than other areas, others weaker, and therefore fractures may form easier and deeper along weaker areas of the wellbore.

Consequently, as fracturing fluid is pumped into the wellbore, the dominant fractures expand and receive more fluid while the marginal fractures are not affected. In order to address this, diverters are used to plug or block the dominant fractures. This causes the fracturing fluid to be diverted away from the dominant fractures to the marginal fractures thereby causing the marginal fractures to propagate and expand.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other advantages and features of the disclosure can be obtained, a more particular description of the principles briefly described above will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. Understanding that these drawings depict only exemplary embodiments of the disclosure and are not therefore to be considered to be limiting of its scope, the principles herein are described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 depicts an example wellbore operating environment in which a diversion and fracturing treatment may be carried out, in accordance with various aspects of the present disclosure;

FIG. 2A depicts a desired flow distribution for a zone for in which a diversion and fracturing treatment has been carried out, in accordance with various aspects of the present disclosure;

FIG. 2B depicts a desired flow distribution for a zone in which a diversion treatment has been carried out, in accordance with various aspects of the present disclosure;

FIG. 3A depicts a downhole portion a wellbore undergoing a diversion treatment, in accordance with various aspects of the present disclosure;

FIG. 3B depicts a downhole portion a wellbore undergoing a diversion treatment, in accordance with various aspects of the present disclosure;

FIG. 3C depicts a downhole portion a wellbore undergoing a diversion treatment, in accordance with various aspects of the present disclosure;

FIG. 3D depicts a downhole portion a wellbore undergoing a diversion treatment, in accordance with various aspects of the present disclosure;

FIG. 3E depicts a downhole portion a wellbore undergoing a diversion treatment, in accordance with various aspects of the present disclosure;

FIG. 4 is a flowchart of an example method for determining a diversion plan, in accordance with various aspects of the subject technology;

FIG. 5 is a schematic diagram of an example computing device architecture, in accordance with some examples;

FIG. 6A is a graph illustrating an example rate control schedule based on a downhole rate sequence, in accordance with various aspects of the subject technology;

FIG. 6B is a graph illustrating an example rate control schedule taking into account surface parameters, in accordance with various aspects of the subject technology;

DETAILED DESCRIPTION

Various embodiments of the disclosure are discussed in detail below. While specific implementations are discussed, it should be understood that this is done for illustration purposes only. A person skilled in the relevant art will recognize that other components and configurations may be used without parting from the spirit and scope of the disclosure.

Additional features and advantages of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or can be learned by practice of the herein disclosed principles. The features and advantages of the disclosure can be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features of the disclosure will become more fully apparent from the following description and appended claims, or can be learned by the practice of the principles set forth herein.

It will be appreciated that for simplicity and clarity of illustration, where appropriate, reference numerals have been repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the embodiments described herein. However, it will be understood by those of ordinary skill in the art that the embodiments described herein can be practiced without these specific details. In other instances, methods, procedures, and components have not been described in detail so as not to obscure the related relevant feature being described. The drawings are not necessarily to scale and the proportions of certain parts may be exaggerated to better illustrate details and features. The description is not to be considered as limiting the scope of the embodiments described herein.

Diversion treatments during hydraulic fracturing may be used to block larger dominant fractures thereby diverting fluid to smaller marginal fractures thereby causing them to propagate and expand. The proper use of diversion treatments increases the size of marginal fractures thereby increasing the production from such fractures and making the wellbore more productive. Accordingly, the proper placement of diverter materials into fractures is a factor in determining how effective a diversion treatment will be in shifting flow from dominant fractures to marginal ones. If a material is placed properly into the dominant fractures, enough backpressure can be created to retard (or completely stop) growth of fractures in those clusters and initiate growth in others. At the same time, though, a diversion treatment can provide no benefit, or even make matters worse, if diverter material is sent to the incorrect or non-desired clusters. As a result, marginal fractures may be accidentally blocked off entirely by the diversion materials and effectively prevent them from being reopened and treated as designed.

Placement of a sufficient amount of diverter in one or more predetermined fractures while avoiding placement in one or more others may be carried out by increasing or decreasing the flow rate of the diverter material at specific times as the diverter material proceeds down the wellbore past the dominant and/or marginal fractures. In some instances, the diverter material and flow rate is controlled to bypass marginal fractures and deliver to dominant fractures. This may involve decreasing the flow rate as the diverter material passes by dominant fractures, and increasing the flow rate as the diverter material passes by marginal fractures. The flow rate as the diverter material passes by dominant fractures is sufficiently low such that the diverter material enters and forms a plug thereby blocking fluid entry into the dominant fracture. The flow rate as the diverter material passes by marginal fractures is such that the diverter material avoids entry into the marginal fracture and passes by without substantial entry. On the surface, the control of the flow rate can be carried out by electric pumps, or other pumps which are sufficiently responsive to adjust the flow rate in the proper time frame causing the diverter material to enter or pass by predetermined fractures.

A plurality of factors may impact delivery, including, but not limited to, the flow rate distribution among the fractures, the amount of diverter material required to block a fracture, the transport efficiency of the diverter material within the carrier fluid, the composition profile of the diverter material mixed at the surface, a translational time delay regarding the time it takes for a rate change at the surface to translate to a rate change downhole, and an equipment delay regarding the time it takes for a rate change command to result in an actual change in rate at the surface.

Disclosed herein is a method and system for controlling the placement of diverter material to predetermined fractures while avoiding placement in other fractures. A diversion plan may be developed which takes into account factors which affect delivery of the diverter material to dominant fractures while avoiding delivery to marginal fractures. A concept underlying aspects of the present disclosure is that diversion material flows into and/or past fractures in a sequential manner as it passes through a wellbore. Accordingly, the amount of material placed in one or more fractures can be effectively controlled by precisely sequenced increases and reductions in the flow rate of fluid injected from the surface.

Accordingly, a flow rate control sequence may be devised for modulating the flow rate at the surface, so as to increase and/or reduce the rate of flow at specific times and increments so that the flow rate of the diverter material downhole is correspondingly reduced or increased such that it enters dominant fractures and avoids entry of marginal fractures. To achieve this, a diversion plan may be developed involving a plurality of planning stages. These stages may include a first overall planning stage in which a desired flow distribution is developed, a second downhole planning stage involving factors which effect a downhole rate schedule, and a third surface planning stage taking into account parameters at the surface which may impact a diversion plan. Each of these planning stages may be updated or revised based on the results and constraints of the other planning stages

In the first overall planning stage, a desired wellbore flow distribution is developed. In particular, a desired flow distribution among the fractures is determined along with the amount of diverter material required to achieve that flow distribution. This planning stage may be developed by first determining the current flow distribution, namely, how the total flow rate within the wellbore is distributed amongst the available fractures. This distribution assists in identifying which fractures are dominant (high flow rate) and which are marginal (low flow rate). This may be determined by testing and/or use of a near-wellbore geometry or pressure drop model (referred to herein as “M5”). A desired flow rate distribution is determined that may the desired or optimal flow rate distribution among the fractures for fracturing or for production. The desired flow rate distribution is achieved by blocking certain dominant fractures so that the marginal fractures can be expanded. Accordingly, the amount of diverter material, provided in mass or concentration, required to block the dominant fractures is also determined. This may involve determining how much resistance that a given amount of diverter material adds to flow entering a fracture once the diverter material is placed. A diversion pressure drop/resistance model (referred to herein as “M6”) may also be used for this process. Therefore, the first stage assists in determining how much material is needed and where it should be placed.

A flow rate control sequence may be determined based on the desired flow distribution and the placement of the diverter material in the predetermined fractures to achieve the desired flow distribution. The fluid at the surface may include a carrier fluid and the diverter material. The flow rate control at the surface, where the fluid is injected, is increased or decreased to deliver the diverter material in the predetermined dominant fractures, while avoiding delivery into the marginal fractures.

In a second downhole planning stage, the effect of downhole transport on the diverter material to the plurality of fractures is determined, and the flow rate sequence updated as a result. This effect may be determined by employing a transport efficiency model (referred to herein as “M3”), which takes into account the difference in momentum between the diverter material and the carrier fluid. As a result of this difference in momentum, the diverter material may have a different flow rate than the carrier fluid. Furthermore, the diverter material may gradually decrease in concentration as portions of the diverter material are delivered into the dominant fractures as it travels through the wellbore.

Based on the transport efficiency of the diverter material, the diverter material concentration (or mass) entering a fracture or cluster of fractures may be estimated. Accordingly, the flow rate upstream of each fracture, or clusters of fractures, may be tailored to optimize delivery into each dominant fracture and avoid delivery into marginal fractures. This may be referred to as the downhole rate schedule, as it focuses on the flow rate upstream of each fracture. The diverter material makeup, namely the concentration or mass, upstream of each fracture, as well as the flow rate upstream of each fracture may be determined or estimated. The flow rate control sequence at the surface can updated to match the determined concentrations of diverter material delivered into each dominant fracture. The transport efficiency model may also take into account other parameters, such as diverter material properties and perforation properties, and with this additional parameters, may be referred to as model (referred to herein as “M4”).

Based on the effect of downhole determinations made in the second downhole planning stage, it may be determined whether the amount and placement of material determined in the first overall planning stage is achievable. If it is not, the first stage determinations may be revised based on the results of the downhole rate sequence and diverter material amounts determinations in the second stage.

In a third surface planning stage, a surface schedule is determined which takes into account parameters at the surface which impact flow rate control. The diverter material may undergo changes in conditions, such as changes in concentration, mass, volume, or otherwise, as it is transported from the surface to the first fracture or cluster of fractures. A wellbore transport model (referred to herein as “M1”) may be employed to determine changes in the diverter material. Moreover, in this third stage a translational delay is determined. This translational delay is the time it takes for a rate change at the surface to translate to a rate change downhole. This translational delay may also include what a pressure response may be as measured downhole, and/or at the surface. For instance, with a downhole pressure sensor in place, an increase in rate at the surface may be detected as a pressure increase downhole. A wellbore compressibility model (referred to herein as “M2”) may be developed to model the translational delay. By monitoring conditions downhole, such as pressure, the wellbore compressibility model can be updated to match actual conditions for better determination of the time at the surface to change the rate to obtain the desired response downhole. In some embodiments, the model M2 may be based on the compressible Navier-Stokes physics relation which describe the motion of viscous fluid substances.

Furthermore, the third stage may also include an equipment delay determination. This involves determining how quickly a rate change command is actuated into an actual change in rate at the surface. Due to equipment constraints or limitations, there may therefore be effect on rate control and implementation of rate changes. This may be determined based on an equipment control model (referred to herein as “M7”), which models such rate change delay from command to actuation.

Based on surface determinations in the third stage, it may be determined whether the flow rate control sequence determined as a result of the first or second planning stages is achievable. If it is not, the first and second stage determinations may be revised based on the results of the updated flow rate control sequence in the third stage.

FIG. 1 is a schematic view of a wellbore operating environment 100 in which a diversion plan and treatment as disclosed herein may be carried out. As depicted, a wellbore 105 extends from the surface 110 of the earth through the formation 115 formed by a drilling device from a previous drilling operation (not shown). The wellbore 105 has a vertical segment 118 as well as horizontal segment 120. The wellbore 105 has a casing 107 extending along its length and which may be cemented to the inner surface of the wellbore 105. A plurality of sensors 112 may be provided along the length of the wellbore to detect temperature, pressure, or flow rate. The plurality of sensors 112 may include for instance pressure or temperature transducers, or may include fiber optic sensors. As further illustrated, pump equipment 122 is provided in the form of a truck carrying a pump is provided on the surface 110. While a truck is shown, the pump equipment 122 can be in any form, such as a standalone unit, a plurality of pump units, within a vehicle or outside a vehicle, or integrated with a vehicle, and may be on the surface 110 or partially inserted into the wellbore 105. The pump equipment may be electrical pumps, or hydraulic pumps, or pumps capable of quick adjustment of flow rate. A carrier fluid 125 is provided which may be mixed or blended at blender 132 with a diverter material 130, optionally a proppant 134, and pumped by the pump equipment 122 through line 142 into the entrance 135 of the wellbore 105 via fracturing tree 144. The carrier fluid 125 together with the diverter material 130, and any proppant 134 may together be referred to as a diversion treatment fluid 140. The fracturing tree 144 includes various inlets and valves necessary for various fluids, including diversion treatment fluid 140. While the treatment fluid 140 is pumped into the wellbore 105 through the casing 107, in other embodiments, additional tubing, such as coiled tubing, can be inserted within the casing 107 to inject or place the carrier fluid 125 and diverter material 130.

The diverter material 130 is generally provided in the carrier fluid 125 in the form of a pill. A pill may be understood as a quantity of diverter material 130 provided as an interval between columns of the carrier fluid 125. In other words, in practice the carrier fluid 125 is continuously pumped into the wellbore 130. The diverter material 130 is introduced periodically into the carrier fluid 125 as a small volume, concentration or mass of material grouped together. This grouping may be referred to as a pill. The diverter material 130 may be in fluid form or may be a solid, or a semi-solid, a gel, and may be in the form of a particulate, and may be degradable. For convenience, the diverter material as it may be in the form of a pill, may be referred to as a having a concentration (a concentration of solid, semi-solid) or a mass with the carrier fluid 125 or treatment fluid 140. Further the diverter material 130 may have a flow rate which may be the same or different than the carrier fluid 125 depending on the relative form and density of the diverter material 130 and the carrier fluid 125.

The diverter material may be in the form of powder, particulates, chips, fiber, bead, button, ribbon, platelet, film, rod, strip, spheroid, toroid, pellet, tablet, capsule, shaving, any round cross-sectional shape, any oval cross-sectional shape, trilobal shape, star shape, flat shape, rectangular shape, cubic, bar shaped, flake, cylindrical shape, filament, thread, or mixtures thereof

The diverter material may be degradable, and may include salt, graded rock salt, benzoic acid, wax, or oil-soluble resin material. The diverter material may employ degradable materials polymers or co-polymers of esters, amides. Polymers or co-polymers of esters, for example, include substituted and unsubstituted lactide, glycolide, polylactic acid, and polyglycolic acid. Polymers of lactic acid, which may also be called polylactic acid, “PLA,” polylactate or polylactide. Polymers or co-polymers of amides, for example, may include polyacrylamides. The diverter material may be degrade downhole, with such degradation being chemical degradation, melting, dissolving, and may degrade in response to elements in the downhole environment to which the diverter material is exposed, e.g., temperature, presence of moisture, oxygen, microorganisms, enzymes, pH, and the like. The diverter material may be insoluble in water but may degrade in the presence of water, such as a chemical degradation.

The diverter material may be in the form of a particulate. The size of the particulate depends on the requirements of the diversion. As mentioned the particle size of the particulate may range from 30 μm to 8 mm. The particle sizes of particulates may have a multimodal distribution, such as bimodal or trimodal, or have four or five or more modes. One distribution of particles may be in the range of from about 3 mm to about 5 mm, having from about 10% to about 70%, alternatively from 20% to 35% of the total particles, another distribution may have from about 0.85 mm to about 2.4 mm, another distribution may have from about 0.40 mm to less than about 0.85 mm, having from about 10% to about 70%, alternatively from 20% to 35% of the total particles, another distribution of from about 0.210 mm to less than about 0.40 mm having from about 10% to about 70%, alternatively from 20 to 35% of the total particles, another distribution from about 0.100 to less than about 0.180 having from about 10% to about 70%, alternatively from 20% to 35% of the total particles, another distribution from about 0.070 to less than about 0.100 having from about 10% to about 70%, alternatively from 20% to 35% of the total particles, another distribution from 30 μm to 70 μm having from about 10% to about 70%, alternatively from 20% to 35% of the total particles.

Each of the above distributions may be included together, or the distributions may be arranged to include some distributions while not including others. For instance, larger particles from 3 to 5 mm and 0.40 to 0.85 may be included for plugging perforations or fractures. Alternatively such larger particles may be excluded, and instead smaller distributions having particle sizes less than 0.40 mm for use with smaller fractures, or microfractures, or to form a filter cake. The particle sizes and distributions may be modified depending on the wellbore, fractures, processes, and desired diversions.

The carrier fluid 125 may be a base fluid may be an aqueous fluid, and may include water, saltwater, seawater, natural or synthetic brine, or freshwater. The carrier fluid may additionally include gelling agents, such as saccharide gelling agents, hydroxyethylcellulose, guar, xanthan and succinoglycan, as well as crosslinkable gelling agents, and crosslinkers. The gelling agents may be included from 0.1% to 2% of the carrier fluid. The proppants may be included such as sand, bauxite, ceramic materials, glass materials, polymer materials, composite particulates, microspheres. Particulates, such as sand, may have particle size distribution ranges are one or more of 10-20 mesh, 20-40 mesh, 40-60 mesh or 50-70 mesh, depending on the particular size and distribution of formation solids to be screened out by the consolidated proppant particles. Weighting agents may be included in the carrier fluid such as clays, or barite.

Referring again to FIG. 1, a processing facility 150 having a computer system 145 may be provided at the surface 110 for collecting, storing or processing data related to the wellbore operating environment 100. The processing facility may be communicatively coupled, via wire or wirelessly, with the pump equipment 122. The pump equipment 122 may have controls or be controlled by the processing facility 150 including flow rates of the carrier fluid 125, diverter material 130 and treatment fluid 140, as well as obtaining data related to flow rates. Additional data may be obtained maybe obtained regarding the wellbore 105, including flow rate distribution wellbore flow distribution of fluid into the fractures in the wellbore 150, including temperature and/or pressure distributions throughout the wellbore 105, which may be obtained by sensors and/or fiber optics positioned along the length of the casing 107 to detect pressure, temperature and/or flow rates along the length of the wellbore.

Further illustrated in FIG. 1 are fracturing zones 155 and 160 separated by a plug 180. Typically fracturing takes place starting at the end of the wellbore referred to as the toe, and proceeding toward the heel. The wellbore is typically divided into zones as fracturing proceeds separated by plugs. Accordingly, as shown in FIG. 1, the horizontal segment 120 of wellbore 105 includes a heel 165 and a toe 170. A fracturing zone 160 is present near the toe 170 and a fracturing zone 155 closer to the heel 165. The zones 155 and 160 are separated by a plug 180, which prevents the flow of fluid between zones.

The fracturing zone 160 has already been perforated and fractured to form fractures 185. Initially, perforations 195 were formed by a perforation gun. As illustrated, the perforations 195 can be formed in clusters, shown here as three (3). However, one, two, or any plurality of perforations may be formed. When two or more perforations 195 are formed in close proximity, they may be referred to as clusters. After perforations 195 were formed, fracturing fluid was pumped from the surface 110 to expand fractures 185. While two fractures 185 are shown, any number of fractures may be employed, such as 1-10, 2-8, or 4-6, or any combination of the aforementioned ranges.

Referring again to FIG. 1, after zone 160 was fractured, a plug 180 was set allowing the next zone 155 was then set for fracturing. In particular, as shown a plurality of perforations were formed, for example by a perforation gun. These perforations include, perforations were formed in order starting at 220, 225, 230, and 235, in order from the plug 180 and extending to the heal. The perforations 220, 220, 225, 230, and 235 were each formed in clusters of three, however, any number of perforations can be formed, from 1 to 20, 2 to 10, 3 to 6, or any combination of the aforementioned. Subsequent perforation, the perforation gun has been pulled from the zone 155, and optionally a fracturing process additionally conducted. In such case, a treatment fluid, in particular a fracturing fluid, is pumped from the surface into zone 155 with sufficient pressure to expand the fractures. Accordingly, fractures 200, 205, 210 and 215, in order from the plug 180 toward the heel 165 are formed by the perforation gun, and optionally additional fracturing by fluid. For convenience, the term fractures herein are inclusive of the one or more perforations made to begin the fracture. Diverter material is generally placed near the wellbore portion of the fracture, within the perforations or portions of the fracture closest to the wellbore.

As illustrated, dominant fractures 205 and 215 are shown as large fractures, while marginal fractures 210 and 200 are shown as small fractures, which are both smaller than fractures 205 and 215. Further, fluid is received at a faster rate from the wellbore 105 into fractures 205 and 215 as compared to the fractures 205 and 215. Accordingly, as dominant fractures 205 are larger and/or receive fluid at a faster rate they are considered dominant, or more dominant, than marginal fractures 205 and 215. The dominant fractures 205 and 215 may be larger due to various factors including the rock formation around such fractures were softer than the formation rock surrounding the fractures 210 and 200 which may be harder. Accordingly the dominant fractures 205 and 215 receive fluid at a faster rate, and for that reason fracturing fluid and associated fracturing pressures may be lost to such fractures thereby preventing marginal fractures 210 and 200 from adequately expanding to desirable size.

In order to target the marginal fractures 210 and 200 with fracturing fluid pressure and expand their size, a diverter material may be provided to dominant fractures 215 and 205 to plug or otherwise block such fractures. This causes the fracturing fluid to be diverted to the marginal fractures 210 and 200.

Accordingly, in order to place such diverter material and achieve the desired well distribution flow rate distribution for fractures in a wellbore, wellbore diversion plan as disclosed herein may be developed. This may begin with a first overall planning stage.

In the first overall planning stage, it may first be determined how the total overall flow rate within the wellbore is distributed amongst the available fractures. Accordingly, by use of sensors, such as measuring temperature, pressure and/or flow, or alternatively or additionally, by methods such as seismic technology or logging tools, the total flow rate from the wellbore 105 into each of the plurality of fractures, including dominant fractures 205 and 215 marginal fractures 210 and 200 is determined. Temperature and/or pressure may be used to determine flows distributions and flow rates within the wellbore 105 and the flow into the plurality of fractures, and/or flow rates maybe measured directly. Based on this data, and/or physics principles a near-wellbore geometry and/or pressure drop model (M5) may be employed which, for a given set of downhole properties and downhole flow rate, the distribution of the total flow rate amongst the fractures may be determined. The near-wellbore geometry as well as the pressure drop may include the number and placement of fractures, as well as the size and shape of such fractures and associated perforations. The pressure changes, such as drops, may indicate fractures, and shapes and sizes of various portions of the wellbore and perforations/fractures. In some embodiments, the model M5 may be defined by, or be based on the following formula:

ΔP_NwB,j=k_1,jQ_j²+k_2,jQ_j^0.5 (1)

wherein,

ΔP_NwB, j: near wellbore pressure drop for cluster j

k_1,j: perforation friction coefficient for cluster j

k_2,j: tortuosity coefficient for cluster j

Q_j: volumetric flow rate into cluster j

As part of the determination of current flow distribution, or subsequently, the desired flow distribution may be determined. For instance, the expansion of the marginal fractures 210 and 200 into larger fractures, so as to receive more fluid flow from the wellbore (and hydrocarbons in the production phase), may be determined. FIG. 2A illustrates a final desired fluid flow distribution in zone 155, as shown by the growth marginal fractures 210 and 200, which are now shown as the same size as dominant fractures 205 and 215 (as compared to FIG. 1). Similarly, based on temperature, pressure, and/or flow rate data, as well as physics principles a near-wellbore geometry and/or pressure drop model (M5) may be employed which, for a given set of downhole properties and downhole flow rate, the distribution of the total flow rate amongst the fractures may be determined.

The amount and placement of diverter material may be determined so as to achieve the desired fluid flow distribution. FIG. 2B illustrates a desired flow rate distribution after diverter material has been placed for further fracturing zone 155 of FIG. 1. In particular, dominant fractures 215 and 205 may be plugged or otherwise blocked with diverter material 130. Such plugging may involve placing the diverter material into the perforations of such fractures, or portions of fractures near the wellbore 105 (sometimes referred to as near-wellbore).

The amount of diverter material 130 required to plug the dominant fractures 215 and 205 is also determined. In particular, for an amount of diverter material transported to a fracture, it is determined how much resistance that diverter material adds to flow entering that fracture once the material is placed. A diversion pressure drop model and/or resistance model (M6) may be employed for this determination, developed based on empirical data and/or physics principles. With this, the amount of diverter material to partially or fully plug a dominant fracture may be determined. This amount may be include or be based on concentration, mass and/or volumetric flow rate.

At the surface, the diverter material may be quantified in terms of concentration and volume and in the form of a pill. As the pill enters a fracture, it may be quantified in terms of the mass of diverter material which enters the fracture. The concentration and mass may be related mathematically. For instance, the mass of diverter into a fracture may be the integral of the concentration into that fracture multiple by the volumetric rate into that fracture.

In some embodiments, the model M6 may be defined by, or be based on the following formulas

k_2,j′=k_2,j′+κ_jM_div,j (2)

M_div,j=∫₀^tC_divQ_jds (3)

wherein,

k_2,j′: enhanced tortuosity coefficient for cluster j

κ_j: diversion sensitivity coefficient for cluster j

M_div,j: Cumulative diverter mass into cluster j

Referring to FIG. 1, as shown, zone 155 with the dominant fractures 215 and 205 plugged with diverter material 270 and 270. In particular, the diverter material 270 and 275 is placed to form blocking plug 250 in fracture 215 and/or its perforations 235 as well as blocking plug 255. Accordingly, in order to divert fracturing treatment fluid to enlarge the marginal fractures. The plugging of such dominant fractures 215 and 205 causes fluid flow in the wellbore 105 to be diverted to the marginal fractures 210 and 200 causing them to extend and be larger. For instance such marginal fractures 210 and 200 may grow to be the same size as dominant fractures 215 and 205. Alternatively, such marginal fractures 210 and 200 can be increased to any size whether larger or smaller than fractures 215 and 205, yet larger than their initial sizes.

Subsequent determining the placement and amount of diverter material required to achieve the desired flow distribution, a flow rate control sequence for injecting the diverter material may be determined. In particular, with knowledge of the placement of the perforations and fractures, and required amounts of diverter material, a flow rate sequence can be determined. In particular, the pump rate of the treatment fluid pumped at the surface may be adjusted to deliver the diverter material into the dominant fractures while avoiding delivery into the marginal fractures. In particular, a rate change adjustment can be made to decrease flow rate as diverter material passes by the dominant fractures and a flow rate increase adjustment made as the diverter material passes by the marginal fractures. This way diverter material enters the dominant fracture as the diverter material passes by the dominant fracture, and furthermore, the diverter material avoids entry into the marginal fracture as the diverter material passes by the marginal fractures. This causes at least a portion of the diverter material into the dominant fracture at least partially blocking the dominant fracture, while avoiding substantial delivery of the diverter material into the marginal fracture. For example a rate control sequence may be made to place the diverter material 270 and 270 into the perforation clusters 235 and 225 respectively, as shown in FIG. 2B, such as slowing the rate when diverter material from the surface passes by dominant fractures 215 and 205, and increasing the rate as the diverter material passes by marginal fracture 210.

The actual results of the diverter placement after the first overall planning stage may be determined based on measurements downhole, such as pressure, temperature and flow rates. The data may be provided as inputs to improve the overall planning stage. This as well as, models M5 and M6 may be improved or adapted based on machine learning techniques. For example, as disclosed herein and throughout the present disclosure, machine learning techniques may include support vector machines, artificial neural networks, K-nearest neighbors, regression techniques, decision tree learning, random forest regressors, random forest classifiers, or a combination of different techniques may be used to improve the first overall planning stage and models M5 and M6.

In a second downhole stage of planning, the accuracy and precision of delivery of the diverter material can be enhanced by determining and controlling the flow rate path downhole. Therefore, subsequent the initial planning stage, an optimal downhole placement schedule is determined. This downhole flow rate schedule allows for customization of the flow rate for each fracture.

In order to determine the downhole rate schedule, the transport efficiency of the diverter material may be determined. Due to differences in momentum the diverter material may have a different flow rate than the carrier fluid.

In particular, because the diversion material typically have a specific gravity greater than one (1), the momentum of the diverter materials will be different than the carrying fluid. The difference in momentum causes the diverter materials to not follow the carrier fluid flow exactly, such that there is a difference in flow rate between the diverter material and the carrier fluid. This can be referred to as the transport efficiency of the diverter material in the carrier fluid. A transport efficiency model (M3) may be determined based on empirical data, historical data, testing, or physics models.

In some instances, the transport efficiency model is defined by the formula:

$\begin{matrix} R_{i} = \frac{C_{i} Q_{i}}{C_{up} Q_{up}} & (4) \end{matrix}$

wherein R_iis transport efficiency,

C_iis the concentration of the diverter material that will enter into a fracture i,

C_upis the concentration upstream of a fracture i,

Q_iis the volumetric flow rate of the diverter material into a fracture i,

Q_upis the volumetric flow rate of the diverter material upstream of a fracture i, wherein fracture i comprises at least the dominant fracture.

The fracture i may be any of the dominant and/or marginal fractures in which at least apportion of the diverter material enters. The R_imay be estimated based on measured data, or from data based on historical or current wellbores, and/or based on physics models. The value of R_ican be the function of many factors, including perforation property such as orientation, the size of perforations, flow rates, and other variables. The R_i, along with the two flow rates Q_iand Q_up, and the upstream concentration C_up, the above formula (1) can be solved to estimate the diverter concentration C_ientering a fracture i.

The transport efficiency model may also be determined as a function of other parameters, such as diverter material properties, such as amount, composition, mass, shape of particulates, distribution, as well as perforations properties, including perforation size and orientation, referred to herein as transport efficiency model (M4). Such model can be defined as R_i=(Q_i, Q_up, [diverter material properties], [per f oration material properties], . . . )

Accordingly, rather than altering the total flow once to place a diverter into a desired fracture, such a dominant fracture, as disclosed herein the upstream rate can be tailored for each fracture. For instance, it may be desirable to increase the upstream rate for a first fracture, and have it decreased for the next, and again adjusted or modulated for a following fracture. The present disclosure provides for the effective upstream rate of the diverter material (and carrier fluid as well) to be customized for each fracture.

Referring again to FIG. 1, it may be determined based on the first overall planning stage to place an amount of diverter material in perforations 230 of dominant fracture 210, for instance 60 lbs, and an amount of diverter material in perforations 220 of dominant fracture 205, for instance 40 lbs, while placing zero lbs of diverter material in perforations 230 of fracture 210 and perforations 220 of fracture 200. FIGS. 3A-3E illustrate downhole placement and determination of a downhole rate schedule of diverter material into the dominant fractures 210 and 200.

FIG. 3A depicts a downhole portion of the wellbore 105, namely zone 155 of the wellbore 105, undergoing a diversion treatment according to the present disclosure. In particular, the carrier fluid 125 includes diverter material in the form of pill 265. The carrier fluid 125 may have the same or different flow rate as pill 265, with differences due to the momentum of the diverter material due to its mass. The pill 265 is shown upstream of dominant fracture 215 and cluster of perforations 235. The pill 265 has a first mass or a first concentration C₁upstream and has an upstream flow rate Q₁. Upstream means closer along the length of the wellbore 105 in the direction toward the entrance 135. As the pill 265 passes by cluster of perforations 235 of dominant fracture 215, the relative flow rate Q₁of the pill 265 can be adjusted to be sufficiently slowed such that at least a portion of the pill 265 enters the cluster of perforations 235 of fracture 215. For instance it may be desired, based on the planning stage, to place 60 lbs of diverter material into clusters 235. Once the desired amount of diverter material entering the cluster of perforations 235 approaches 60 lbs, the flow rate can be gradually increased.

FIG. 3B depicts a downhole portion of the wellbore 105, namely zone 155 of the wellbore 105, with diverter material 270 having entered the cluster of perforations 235 thereby plugging and blocking the perforations 235 of dominant fracture 215. The blocking of the dominant fracture 215 prevents entry of fluid from the wellbore 105. The perforations 235 are shown illustrated as fully blocked, however, in other embodiments, the perforations can be partially blocked to permit some flow into the fraction.

As a result of a portion of the diverter material having entered the perforations 235, the pill 265 will have lower mass and concentration after having passed the dominant fracture 215. Accordingly, pill 265 will have second concentration C₂upstream of dominant fracture 210 and cluster of perforations 230. Notably, the pill 265, while upstream of dominant fracture 210 is downstream of fracture 215.

Given that it is intended to enlarge marginal fracture 210, it is desirable to avoid delivery of any diverter material into that fracture or its perforations 230. Accordingly, the flow rate of the pill 265 can be sufficiently increased so that it bypasses the marginal fracture without substantially entering the marginal fracture. Such flow rate may be Q₂and greater than flow rate Q₁in FIG. 3A.

FIG. 3C depicts a downhole portion of the wellbore 105, namely zone 155 of the wellbore 105, with pill 265 upstream of dominant fracture 205 and its cluster of perforations 225. While upstream of dominant fracture 205, it is downstream of fracture 210. As no diverter material entered the previous marginal fracture 210 or its cluster of perforations 230, the pill 265 may still have the same mass or concentration C₂. However, as it intended to place at least portion of pill 265 into the cluster of perforations 225 and/or the dominant fracture 205, the flow rate of the pill 265 must be sufficiently decreased so that it enters the cluster of perforations 225 of fracture 205. Accordingly the flow rate of pill 265 can be adjusted to have a decreased upstream flow rate Q₃. For instance it may be desired, based on the planning stage, to place 40 lbs of diverter material into clusters 225. Once the desired amount of diverter material entering the cluster of perforations 225 approaches 40 lbs, the flow rate can be gradually increased.

The upstream flow rate Q₃may also depend on the orientation of the perforations, the size of perforations and the fracture, and the total flow rate of fluid in wellbore 105. The flow rate Q₃can be lower than Q₂and may be the same or different than Q₁. As the pill 265 travels downhole its mass or concentration changes, and therefore the flow rate will also correspondingly require adjustment to deliver or avoid delivery of divert material into a perforation.

FIG. 3D depicts a downhole portion of the wellbore 105, namely zone 155 of the wellbore 105, with diverter material 275 having entered the cluster of perforations 225 thereby plugging and blocking the perforations 225 of dominant fracture 205. The blocking of the dominant fracture 205 prevents entry of fluid from the wellbore 105. The perforations 225 are shown illustrated as fully blocked, however, in other embodiments, the perforations can be partially blocked to permit some flow into the fraction, thereby being partially blocked.

As shown in FIG. 3D, a portion of the pill 265 entered the perforations 245 of dominant fracture 215, shown as diverter material 275. Further, as a result of a portion of the diverter material having entered the perforations 225, the pill 265 will have lower mass and concentration after having passed the dominant fracture 205. Although the illustrated embodiment shows some amount of diverter material remaining as pill 265, in other embodiments, the remaining amount of diverter material will have been provided in the last cluster of perforations of the last dominant fracture, in this case 205, such that the pill 265 does not enter a recirculation zone near the plug 180. Accordingly, pill 265 will have third concentration C₃upstream of marginal fracture 200 and cluster of perforations 230, which may be zero, or less than C₂. The pill 265, while upstream of marginal fracture 200 is downstream of dominant fracture 205.

Given that it is intended to enlarge marginal fracture 200, it is desirable to avoid delivery of any diverter material into its perforations 230. Accordingly, the flow rate of any remaining pill 265 can be sufficiently increased so that it bypasses the marginal fracture without substantially entering the marginal fracture. Such flow rate may be Q₄and greater than flow rate Q₃in FIG. 3C.

Accordingly, as shown in FIG. 3E, the perforations 235 of dominant fracture 215 have been plugged with diverter material 270 and perforations 225 of dominant fracture 205 have been plugged with diverter material 275. Further, the perforations 230 of marginal fracture 210 and perforations 220 of marginal fracture 210 have been left open. Accordingly, treatment fluid pumped from the surface at high pressure sufficient to fracture formation rock will be diverted to the marginal fractures 210 and 200 thereby expanding such fractures, as shown in FIG. 2B. This results in achieving the desired fluid desired flow rate distribution for the fractures in the wellbore.

As illustrated in FIGS. 3A-3E, the flow rate and concentration (or mass) of the diverter material pill is determined upstream and within each fracture, allowing a tailored result for each fracture. This downhole rate schedule is used as a basis for the flow rate control sequence to place the diverter material to achieve the desired flow rate distribution in the wellbore.

The actual results of the diverter placement after the second downhole planning stage may be determined based on measurements downhole, such as pressure, temperature and flow rates among other measurements. The data may be provided as inputs to improve the first overall planning stage and the second downhole planning stage. This as well as, models M3 and M4 may be improved or adapted based on machine learning techniques discussed herein.

In view of the aforementioned, based on the first overall planning stage, the desired flow distribution and amount of diverter material is determined. Further, in a second downhole planning stage, the optimal downhole rate schedule and downhole diverter material profile is determined. Moreover, results of the second planning stage with respect the rate schedule or the surface diverter material may be used to determine whether the initial plan was achievable, which may be updated or revised in view of the second downhole planning stage. The second downhole planning stage can again be carried out based on the updated first overall planning stage.

After the downhole rate schedule and pill profile are determined, the third surface planning stage can be carried out. The surface planning stage takes into account parameters which may cause a translational delay at the surface which may impact the flow rate control sequence. For instance, factors include the time for the diverter material to travel from the surface to downhole, the changes in the diverter material concentration as it travels from the surface to downhole thereby affecting how the diverter material is to be prepared at the surface, and the delay in actuating surface equipment.

Initially, the pill profile at the surface can be prepared based on how the diversion materials are transported downhole and in what condition, concentration, volume, and mass, as they arrive at the perforation cluster of the first fracture. This may include the diverter material concentration or mass in the pump, at any blender used, or other tank, including concentration at the entrance (wellhead), and how that may change as the diverter material travels downhole. For instance, once it is known the concentration, mass and/or volume that will enter the fractures downhole, for instance concentrations C₁-C₃of pill 265 in FIGS. 3A-3D, then the diverter material pill profile at the surface may be prepared. In particular, with knowledge of the concentration upstream of a first fracture, such as the concentration of the pill 265 in FIG. 3A, which is just upstream of fracture 215, the pill at the surface 110 can be prepared for pumping into entrance 135 of the wellbore 105. The changes in the diverter material pill can be based on a wellbore transport model (M1). The wellbore transport model may be developed based on history of the wellbore, empirical data, or physics. For instance testing can be carried out which measures the changes in concentration, mass or volume of the diverter material pill as it travels from the entrance 135 (or pump equipment 122) to the first fracture 215, or other fractures. An some embodiments, model M1 may be based on the following formula:

$\begin{matrix} \frac{\partial c_{div}}{\partial t} + \frac{\partial (C_{div} u)}{\partial x} = 0 & (5) \end{matrix}$

wherein,

u: velocity of fluid in wellbore

C_div: diverter concentration

Additionally, the impact on the flow rate sequence by the translational delay may be determined. This translational delay is the time it takes for a rate change at the surface to translate to a rate change downhole. For instance, with a change in pumping rate of pump equipment 122 at the surface 110, there may be delay until the rate of a pill downhole, such as pill 265 in FIGS. 3A-3D, is correspondingly changed. Accordingly, the flow control sequence can be updated based on the translational delay.

The translational delay can be based on wellbore or fluid compressibility model (M2), which models how quickly the rate change at the surface translates to a rate change downhole. This wellbore or fluid compressibility model may also indicate what the related pressure response may look like at the surface. Pressure, temperature and flow changes may be detected by sensors downhole, such as by downhole with sensors 112 and/or at the surface 110 for instance by processing facility 150. The sensors 112 can be used to monitor downhole pressure. Accordingly, an increase in pressure as measured at the surface will be seen as an increase in pressure as measured downhole, for instance by sensors 112. By monitoring the pressure at the surface and how this is pressure is reflected downhole, the wellbore or fluid compressibility model can be adapted to match the actual conditions for better determination of the time at surface to change rate to obtain the desired response downhole. A number of different techniques, including machine learning techniques may be used to adapt and improve the fluid compressibility model detection model. The data received from the sensors 112 can be used as at least one of the inputs for adapting the model to match actual conditions downhole.

Accordingly, the rate change at the surface, which may be measured by pressure changes at the surface and/or downhole sensors 112, can be timed to decrease rate of the downhole pill just as pill 265 is passing perforations 235 of dominant fracture 215 in FIG. 3A, and then increase rate just as pill 265 passes perforations 230 of marginal fracture 210 in FIG. 3B, and then again decrease rate as pill 265 passes dominant fracture 205.

Additionally, the third surface planning stage may also include an equipment delay determination. This involves determining how quickly a rate change command is actuated into an actual change in rate at the surface. For instance, the delay in actuating the pump equipment 122 either due to the equipment itself, or as by controls such as at processing system 145, there may be a delay in how quickly a rate change command is actuated into an actual change at the surface 110 and entrance 135 where the treatment fluid 140 is injected. Equipment may include additionally include blender, blender rate, blender or storage tank (or tub) properties, tub volume, distance of piping between equipment, as well as to the wellbore entrance. The equipment delay may be determined based on an equipment control model (M7), which models such rate change delay from command to actuation. For instance, in pumping equipment, there can be a difference between a setpoint command and actual output, which may affect flow rates, which can be accounted for in model M7.

Once the third surface planning stage is completed, it may be determined if the results of the first overall planning stage and second downhole planning stage are achievable or result in error. Accordingly, based on the results of the third surface planning stage, the first overall planning stage or second downhole planning stage may be updated.

Based on the first overall planning stage, the desired flow distribution and amount of diverter material is determined. Further, in a second downhole planning stage, the optimal downhole rate schedule and downhole diverter material profile is determined. Moreover, results of the second planning stage with respect the rate schedule or the surface diverter material may be used to determine whether the initial plan was achievable, or result in error, and which may be updated or revised in view of the second downhole planning stage. The second downhole planning stage can again be carried out based on the updated first overall planning stage.

The actual results of the diverter placement after the third surface planning stage may be determined based on measurements downhole, such as pressure, temperature and flow rates among other measurements. The data may be provided as inputs to improve the first overall planning stage, the second downhole planning stage, and the third surface planning stage. This as well as, models M1, M2, and M7 may be improved or adapted based on machine learning techniques discussed herein.

In view of the aforementioned three planning stages a flow rate control sequence for injecting a fluid comprising a carrier fluid and a diverter material into an entrance of the wellbore at a surface of the earth. For instance, in the first planning stage, models M5 and M6 may be combined to determine the optimal amount of diversion material per cluster of perforations (and other properties, such as concentration and material type) that would achieve the desired flow distribution outcome. In the second downhole planning stage, models M3, M4, as well as M5, may be used to determine the make-up of the diverter material pill upstream of each of one or more perforation clusters, as well as the correct sequencing of the downhole rates in order to best match the desired diverter material pill mass and/or concentration profiles to each cluster of perforations. Once such pill characteristics upstream of the in the third surface planning stage, models M1 can be sued to determine how the divert material pill should be mixed at the surface and pumped downhole. Additionally model M2, along with its adjustments via downhole monitoring, along with model M7, may be used to determine which the rate change commands should be made at the surface in order to match the desired downhole rate sequence as closely as possible.

Furthermore according to the disclosure herein, in some circumstances, the most optimal distribution of materials into each cluster of perforations may not be feasible due to equipment limitations and/or the current state of the wellbore environment (and formation near the wellbore) as based on model M5. Therefore, this process may involve an additional feedback loop that takes such feasibility constrains into consideration to update other models at different planning stages to obtain the optimal flow rate control sequence.

FIG. 4 is a diversion plan flow process 400 for developing a flow rate control sequence for achieving a desired flow distribution among the fractures. As illustrated, the process may begin with a flow distribution history 405, which may include data already collected regarding perforation, fracturing, or zones already completed for one or more wellbores. Furthermore, remaining design of the wellbore 410 may be included as initial data. The flow then proceeds to first overall planning stage 415. In the first overall planning stage, the desired flow distribution within a wellbore may be determined. This may be based on a near-wellbore geometry and/or pressure drop model (M5), which may be used to determine how the total flow rate in the wellbore is distributed amongst the available fractures. Additionally, diverter material amounts may be determined which are required to achieve the desired flow distribution. This may be based on a diversion pressure drop and/or resistance model (M6), which may be used to determine for a given amount of diverter material transported to a fracture, how much resistance that diverter material adds to flow entering the fracture once placed.

The flow then proceeds to second downhole planning stage 420. In this stage, a downhole rate schedule is determined. In this stage, factors which affect the placement of diversion downhole are considered. In particular, the amount of diverter material, which may be the mass, concentration, or amount of diverter material entering each of the desired downhole fractures is determined. The upstream flow rate of the divert material for each of the fractures may be customized and determined. This may be determined based on transport efficiency model M3, or M4, where in M4, transport efficiency is a function of additional parameters such as diverter material properties and perforation properties.

After the second downhole planning stage 420, it is determined in error check 425 whether the results from the first overall planning stage 415 are still valid and achievable. If not, and there is error, then the flow proceeds back to the first overall planning stage 415 which can be updated based on the results from second downhole planning stage 420. With each flow back from error check 425 to the first overall planning stage 415, machine learning techniques as discussed herein may also be employed to adapt or improve the models, estimates and results obtained at each stage.

Once the results of first overall planning stage 415 second downhole planning stage 420 are valid, the flow proceeds to the third surface planning stage 430. In this stage, the downhole translational delay is determined, for example the delay in time for changes in rate at the surface to be translated downhole. This may be determined based on a wellbore transport model M2. Additionally, the diverter material pill profile at the surface can be determined. This may be based on a wellbore or fluid compressibility model M1. Further, the equipment delay time from command to actuation into a change at the pump rate in the fluid at the surface is determined, and which can be determined based on an equipment control model M7.

The flow then the proceeds to error check 435, whether the results from the third surface planning stage 430 are still valid and achievable. If not, and there is error, then the flow proceeds back to the first overall planning stage 415 and second downhole planning stage 420, which can be updated based on the results from third surface planning stage 430. With each flow back from error check 435 to the first overall planning stage 415, machine learning techniques as discussed herein may also be employed to adapt or improve the models, estimates and results obtained at each stage.

Once the results of the third surface planning stage 430 are valid, the diversion treatment can be executed based on the developed diversion plan. The diversion treatment includes a flow rate control sequence for injecting the treatment fluid with the diverter material to place the material in the desired fractures. The smaller marginal fractures which remain unplugged with diverter material may then be expanded.

FIG. 5, which illustrates an example computing device architecture 800 which can be employed to perform various steps, methods, and techniques disclosed herein. The various implementations will be apparent to those of ordinary skill in the art when practicing the present technology. Persons of ordinary skill in the art will also readily appreciate that other system implementations or examples are possible.

As noted above, FIG. 5 illustrates an example computing device architecture 500 of a computing device which can implement the various technologies and techniques described herein. For example, the computing device architecture 500 can implement the various training systems, detection systems, data processors, downhole tools, servers, or other computing devices and perform various steps, methods, and techniques disclosed herein. The components of the computing device architecture 500 are shown in electrical communication with each other using a connection 505, such as a bus. The example computing device architecture 500 includes a processing unit (CPU or processor) 510 and a computing device connection 505 that couples various computing device components including the computing device memory 515, such as read only memory (ROM) 520 and random access memory (RAM) 525, to the processor 510.

The computing device architecture 500 can include a cache of high-speed memory connected directly with, in close proximity to, or integrated as part of the processor 510. The computing device architecture 500 can copy data from the memory 515 and/or the storage device 530 to the cache 512 for quick access by the processor 510. In this way, the cache can provide a performance boost that avoids processor 510 delays while waiting for data. These and other modules can control or be configured to control the processor 510 to perform various actions. Other computing device memory 515 may be available for use as well. The memory 515 can include multiple different types of memory with different performance characteristics. The processor 510 can include any general purpose processor and a hardware or software service, such as service 1 532, service 2 534, and service 3 536 stored in storage device 530, configured to control the processor 510 as well as a special-purpose processor where software instructions are incorporated into the processor design. The processor 510 may be a self-contained system, containing multiple cores or processors, a bus, memory controller, cache, etc. A multi-core processor may be symmetric or asymmetric.

To enable user interaction with the computing device architecture 500, an input device 545 can represent any number of input mechanisms, such as a microphone for speech, a touch-sensitive screen for gesture or graphical input, keyboard, mouse, motion input, speech and so forth. An output device 535 can also be one or more of a number of output mechanisms known to those of skill in the art, such as a display, projector, television, speaker device, etc. In some instances, multimodal computing devices can enable a user to provide multiple types of input to communicate with the computing device architecture 500. The communications interface 540 can generally govern and manage the user input and computing device output. There is no restriction on operating on any particular hardware arrangement and therefore the basic features here may easily be substituted for improved hardware or firmware arrangements as they are developed.

Storage device 530 is a non-volatile memory and can be a hard disk or other types of computer readable media which can store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, solid state memory devices, digital versatile disks, cartridges, random access memories (RAMs) 525, read only memory (ROM) 520, and hybrids thereof. The storage device 530 can include services 532, 534, 536 for controlling the processor 510. Other hardware or software modules are contemplated. The storage device 530 can be connected to the computing device connection 505. In one aspect, a hardware module that performs a particular function can include the software component stored in a computer-readable medium in connection with the necessary hardware components, such as the processor 510, connection 505, output device 535, and so forth, to carry out the function.

For clarity of explanation, in some instances the present technology may be presented as including individual functional blocks including functional blocks comprising devices, device components, steps or routines in a method embodied in software, or combinations of hardware and software.

In some embodiments the computer-readable storage devices, mediums, and memories can include a cable or wireless signal containing a bit stream and the like. However, when mentioned, non-transitory computer-readable storage media expressly exclude media such as energy, carrier signals, electromagnetic waves, and signals per se.

Methods according to the above-described examples can be implemented using computer-executable instructions that are stored or otherwise available from computer readable media. Such instructions can include, for example, instructions and data which cause or otherwise configure a general purpose computer, special purpose computer, or a processing device to perform a certain function or group of functions. Portions of computer resources used can be accessible over a network. The computer executable instructions may be, for example, binaries, intermediate format instructions such as assembly language, firmware, source code, etc. Examples of computer-readable media that may be used to store instructions, information used, and/or information created during methods according to described examples include magnetic or optical disks, flash memory, USB devices provided with non-volatile memory, networked storage devices, and so on.

Devices implementing methods according to these disclosures can include hardware, firmware and/or software, and can take any of a variety of form factors. Typical examples of such form factors include laptops, smart phones, small form factor personal computers, personal digital assistants, rackmount devices, standalone devices, and so on. Functionality described herein also can be embodied in peripherals or add-in cards. Such functionality can also be implemented on a circuit board among different chips or different processes executing in a single device, by way of further example.

The instructions, media for conveying such instructions, computing resources for executing them, and other structures for supporting such computing resources are example means for providing the functions described in the disclosure.

In the foregoing description, aspects of the application are described with reference to specific embodiments thereof, but those skilled in the art will recognize that the application is not limited thereto. Thus, while illustrative embodiments of the application have been described in detail herein, it is to be understood that the disclosed concepts may be otherwise variously embodied and employed, and that the appended claims are intended to be construed to include such variations, except as limited by the prior art. Various features and aspects of the above-described subject matter may be used individually or jointly. Further, embodiments can be utilized in any number of environments and applications beyond those described herein without departing from the broader spirit and scope of the specification. The specification and drawings are, accordingly, to be regarded as illustrative rather than restrictive. For the purposes of illustration, methods were described in a particular order. It should be appreciated that in alternate embodiments, the methods may be performed in a different order than that described.

Where components are described as being “configured to” perform certain operations, such configuration can be accomplished, for example, by designing electronic circuits or other hardware to perform the operation, by programming programmable electronic circuits (e.g., microprocessors, or other suitable electronic circuits) to perform the operation, or any combination thereof.

The various illustrative logical blocks, modules, circuits, and algorithm steps described in connection with the examples disclosed herein may be implemented as electronic hardware, computer software, firmware, or combinations thereof. To clearly illustrate this interchangeability of hardware and software, various illustrative components, blocks, modules, circuits, and steps have been described above generally in terms of their functionality. Whether such functionality is implemented as hardware or software depends upon the particular application and design constraints imposed on the overall system. Skilled artisans may implement the described functionality in varying ways for each particular application, but such implementation decisions should not be interpreted as causing a departure from the scope of the present application.

The techniques described herein may also be implemented in electronic hardware, computer software, firmware, or any combination thereof. Such techniques may be implemented in any of a variety of devices such as general purposes computers, wireless communication device handsets, or integrated circuit devices having multiple uses including application in wireless communication device handsets and other devices. Any features described as modules or components may be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques may be realized at least in part by a computer-readable data storage medium comprising program code including instructions that, when executed, performs one or more of the method, algorithms, and/or operations described above. The computer-readable data storage medium may form part of a computer program product, which may include packaging materials.

The computer-readable medium may include memory or data storage media, such as random access memory (RAM) such as synchronous dynamic random access memory (SDRAM), read-only memory (ROM), non-volatile random access memory (NVRAM), electrically erasable programmable read-only memory (EEPROM), FLASH memory, magnetic or optical data storage media, and the like. The techniques additionally, or alternatively, may be realized at least in part by a computer-readable communication medium that carries or communicates program code in the form of instructions or data structures and that can be accessed, read, and/or executed by a computer, such as propagated signals or waves.

Other embodiments of the disclosure may be practiced in network computing environments with many types of computer system configurations, including personal computers, hand-held devices, multi-processor systems, microprocessor-based or programmable consumer electronics, network PCs, minicomputers, mainframe computers, and the like. Embodiments may also be practiced in distributed computing environments where tasks are performed by local and remote processing devices that are linked (either by hardwired links, wireless links, or by a combination thereof) through a communications network. In a distributed computing environment, program modules may be located in both local and remote memory storage devices.

It will be appreciated that for simplicity and clarity of illustration, where appropriate, reference numerals have been repeated among the different figures to indicate corresponding or analogous elements. In addition, numerous specific details are set forth in order to provide a thorough understanding of the embodiments described herein. However, it will be understood by those of ordinary skill in the art that the embodiments described herein can be practiced without these specific details. In other instances, methods, procedures and components have not been described in detail so as not to obscure the related relevant feature being described. Also, the description is not to be considered as limiting the scope of the embodiments described herein. The drawings are not necessarily to scale and the proportions of certain parts have been exaggerated to better illustrate details and features of the present disclosure.

The following examples illustrate the aspects of the present disclosure without, however, restricting it thereto.

Examples

In the present examples, a diversion plan was determined including a flow rate control sequence to be implemented from the surface. Initially, in a first overall planning stage, three clusters of perforations were identified, along with the amount of diverter material required (shown in the far column on the right in table 1 below), in weight or mass. The downhole planning stage was carried out by analyzing results from models M3, M4 and M5 to develop a downhole rate schedule along with required mass for reach cluster of perforations.

The results are shown in the following table:

TABLE 1 Optimized downhole rate schedule illustrating close fit to Desired Mass distribution Total Upstream Cluster Upstream Cluster Rate Rate Inflow Conc Conc Inlet Delivered Desired (bpm) (bpm) (bpm) (ppg) (ppg) Vol Mass (lb) Mass (lb) 2.5 2.50 1.88 0.12 0.09 20.23 60.27 60 25 13.20 2.82 0.19 0.11 5.02 4.79 0 10 3.48 3.48 0.21 0.21 3.94 34.95 40

The determination of transport efficiency using models M4 and M5 are provided as follows:

Model M4:

$R_{i} = 30.457 {(\frac{Q_{i}}{Q_{up}})}^{3} + 0.543 (\frac{Q_{i}}{Q_{up}})$

Model M5:

ΔP_i=αq_i^0.5+βq_i²

ΔP_i−ΔP_i+1=0, i=1,2, . . . , N_c−1

Σq_i−Q=0

The above models M4 and M5 were used to determine distribution of flow rate for a given total flow rate. From the above, the desired mass is 60 lbs for the first cluster, zero for the second cluster, and 40 lbs, for the 3^rdcluster. FIG. 6A illustrates the rate control schedule based on the downhole rate schedule, including the total downhole flow rate in barrels per minute (bpm) as a function of time. As illustrated, the rate chart shows a pump rate increase at eight minutes from less than 5 bpm to about 25 bpm, with a decrease shortly thereafter to a rate of about 10 bpm.

Subsequently, the third surface planning stage was carried out, using models M1, M2, and M7 to determine optimal surface rate schedule from optimized downhole rate schedule. The results are shown in Table 2.

TABLE 2 Determination of surface parameters to obtain the downhole concentration profile Mass 100 lb Diverter tub clean volume 3 bbl Main blender rate 22 bpm Diverter Blender rate 5 bpm Tub concentration 0.737 ppg Tub Exit concentration 0.701 ppg Well head concentration 0.131 ppg Diverter concentration Well head concentration 0.131 ppg Downhole concentration 0.118 ppg

The above pump equipment factors were taken into account, as well as determination for the surface diverter material pill profile. The optimized surface rate schedule taking equipment characteristics into account, and resultant expected mass placement after running full optimization procedure including surface constraints, are shown in Table 3.

Cluster 1 Cluster 2 Cluster 3 Desired Mass (lb) 60.00 0.00 40 . . . from optimized 60.27 4.79 34.95 downhole schedule (lb) . . . from optimized 58.84 4.89 36.27 surface schedule (lb)

To determine the above, the models M1, M2, and M7 are provided as follows: Model M1:

- Tube exit concentration C_tub,exit=C_tubexP(−0.0.1Q_tub

$• Wellhead concentration C_{wellhead} = C_{tub, ext} (\frac{Q_{tub}}{Q_{main} + Q_{tub}})$

- Wellhead transport efficiency: C_downhole=C_wellheadexp(−0.0020 Q_slurry)
  Model M2: for this example, assumed incompressible fluid, no delay;
  Model M7: assume surface pumps can change total slurry rate at a rate of 100 bpm/min.

Based on the above a surface rate schedule is determined. FIG. 6B illustrates the surface schedule as a result of the determinations in the surface planning stage. As illustrated, the rate increase at the surface is just prior to the 8 minute mark, and therefor precedes the previously calculated optimized downhole rate schedule sufficiently to take into account the delay in time inherent in equipment.

Numerous examples are provided herein to enhance understanding of the present disclosure. A specific set of statements are provided as follows.

Statement 1: A method including: determining a current flow rate distribution for fractures in a wellbore, the fractures comprising a dominant fracture and a marginal fracture, the dominant fracture receiving fluid at a higher rate from the wellbore than the marginal fracture; determining a desired flow rate distribution for the fractures in the wellbore; and determining a flow rate control sequence for injecting a fluid comprising a carrier fluid and a diverter material into an entrance of the wellbore at a surface of the earth to deliver the diverter material into the dominant fracture and avoid delivery of the diverter material into the marginal fracture to transition from the current flow rate distribution to the desired flow rate distribution.

Statement 2: The method of Statement 1, wherein the flow rate control sequence comprises a flow rate decrease adjustment at the entrance of the wellbore such that the diverter material enters the dominant fracture as the divert material passes by the dominant fracture and a flow rate increase adjustment at the entrance of the wellbore such that the diverter material avoids entry into the marginal fracture as the diverter material passes by the marginal fracture without substantially entering the marginal fracture, thereby delivering at least a portion of the diverter material into the dominant fracture at least partially blocking the dominant fracture and avoiding substantial delivery of the diverter material into the marginal fracture.

Statement 3: The method of any one of the preceding Statements 1-2, further comprising: determining an amount of a diverter material required to at least partially block the dominant fracture to achieve the desired flow rate distribution.

Statement 4: The method of any one of the preceding Statements 1-3 further comprising: estimating a concentration of diverter material that enters the dominant fracture based on a transport efficiency of the diverter material in the carrier fluid, the transport efficiency being based on a difference in flow rate between the diverter material and the carrier fluid.

Statement 5: The method of Statement 4 wherein the estimating is further based on at least one member selected from the group of a perforation property, perforation orientation, and a diverter material property.

Statement 6: The method of any one of the preceding Statements 4-5 wherein the transport efficiency is defined by the formula:

$R_{i} = \frac{C_{i} Q_{i}}{C_{up} Q_{up}}$

wherein R_iis transport efficiency, C_iis the concentration of the diverter material that will enter into a fracture i, C_upis the concentration upstream of a fracture i,Q_iis the volumetric flow rate of the diverter material into a fracture i, Q_upis the volumetric flow rate of the diverter material upstream of a fracture i, wherein fracture i comprises at least the dominant fracture.

Statement 7: The method of any one of the preceding Statements 1-6, wherein the flow rate sequence comprises determining a flow rate of the diverter material upstream from the dominant fracture for delivering at least a portion of the diverter material into the dominant fracture.

Statement 8: The method of any one of the preceding Statements 1-7, wherein the dominant fracture is a first dominant fracture, and the wellbore further comprises a second dominant fracture, the second dominant fracture being downstream from the first dominant fracture, each of the first and second dominant fractures receiving fluid at a higher rate from the wellbore than the marginal fracture, the determining the flow rate sequence further comprises determining a second flow rate of the fluid upstream from a second dominant fracture but downstream from the first dominant fracture for delivering at least a portion of the diverter material to the second dominant fracture at least partially blocking the second dominant fracture.

Statement 9: The method of any one of the preceding Statements 1-8, further comprising updating at least one of the rate control sequence or the amount of diverter material required to block the dominant fracture based on the estimated concentration of diverter material that enters the dominant fracture.

Statement 10: The method of any one of the preceding Statements 1-9, wherein the wellbore comprises a plurality of dominant fractures and a plurality of marginal fractures, each of the plurality of dominant fractures receiving fluid at a higher rate from the wellbore than the marginal fractures, and the method comprising determining a rate control sequence for each of the plurality of dominant fractures and each of the plurality of marginal fractures, the rate control sequence comprising a flow rate decrease adjustment at the entrance of the wellbore such that a portion of the diverter material enters each of the plurality of dominant fractures as the diverter material passes by each of the plurality of the dominant fractures and a flow rate increase adjustment at the entrance of the wellbore such that the diverter material avoids entry into each of the marginal fractures as the diverter material passes by each of the marginal fractures.

Statement 11: The method of any one of the preceding Statements 1-10, wherein the dominant fractures and marginal fractures have perforations arranged in clusters, the flow rate control sequence being based on clusters of the dominant or marginal fractures.

Statement 12: The method of any one of the preceding Statements 1-11, further comprising determining a concentration of the diverter material injected into the entrance of the wellbore at the surface of the earth based on an effect on the concentration of the diverter as it transports from the surface to at least one of the dominant fracture or the marginal fracture.

Statement 13: The method of any one of the preceding Statements 1-12, further comprising determining the rate control sequence based on a translational time delay, the translational time delay comprising the time it takes for flow rate change at the entrance of the wellbore to translate to a flow rate change of the diverter material as it passes at least one of the dominant fracture or the marginal fracture in the wellbore.

Statement 14: The method of any one of the preceding Statements 1-13, wherein the diverter material is injected into the entrance of the wellbore at the surface by pump equipment, the method further comprising determining the rate control sequence further based on a delay in a rate command change input to the pump equipment and a change in rate being actuated by the pump equipment to the diverter material injected at the surface.

Statement 15: The method of any one of the preceding Statements 1-14, wherein the diverter material is injected in the form of a pill.

Statement 16: The method of any one of the preceding Statements 1-15, wherein the fluid is injected by an electric pump.

Statement 17: The method of any one of the preceding Statements 1-16, carrying out an injection of diverter material based on the determined flow rate control sequence.

Statement 18: A system comprising: one or more processors; and a memory storing instructions to: determining a desired flow rate distribution for fractures in a wellbore, the fractures comprising a dominant fracture and a marginal fracture, the dominant fracture receiving fluid at a higher rate from the wellbore than the marginal fracture; and determining a flow rate control sequence for injecting a fluid comprising a carrier fluid and a diverter material into an entrance of the wellbore at a surface of the earth to deliver the diverter material into the dominant fracture and avoid delivery of the diverter material into the marginal fracture to achieve the desired flow rate distribution.

Statement 19: The system of Statement 18, wherein the flow rate control sequence comprises a flow rate decrease adjustment at the entrance of the wellbore such that the diverter material enters the dominant fracture as the divert material passes by the dominant fracture and a flow rate increase adjustment at the entrance of the wellbore such that the diverter material avoids entry into the marginal fracture as the diverter material passes by the marginal fracture without substantially entering the marginal fracture, thereby delivering at least a portion of the diverter material into the dominant fracture at least partially blocking the dominant fracture and avoiding substantial delivery of the diverter material into the marginal fracture.

Statement 20: The system of any one of the preceding Statements 18-19, further comprising: estimating a concentration of diverter material that enters the dominant fracture based on a transport efficiency of the diverter material in the carrier fluid, the transport efficiency being based on a difference in flow rate between the diverter material and the carrier fluid.

Statement 21: The method of any one of the preceding Statements 18-20, further comprising determining a concentration of the diverter material injected into the entrance of the wellbore at the surface of the earth based on an effect on the concentration of the diverter as it transports from the surface to at least one of the dominant fracture or the marginal fracture.

Statement 22: A non-transitory computer readable medium storing instructions that, when executed by one or more processors, cause the one or more processors to: determining a desired flow rate distribution for fractures in a wellbore, the fractures comprising a dominant fracture and a marginal fracture, the dominant fracture receiving fluid at a higher rate from the wellbore than the marginal fracture; and determining a flow rate control sequence for injecting a fluid comprising a carrier fluid and a diverter material into an entrance of the wellbore at a surface of the earth to deliver the diverter material into the dominant fracture and avoid delivery of the diverter material into the marginal fracture to achieve the desired flow rate distribution.

Statement 23: The non-transitory computer readable medium of Statement 22, wherein the flow rate control sequence comprises a flow rate decrease adjustment at the entrance of the wellbore such that the diverter material enters the dominant fracture as the divert material passes by the dominant fracture and a flow rate increase adjustment at the entrance of the wellbore such that the diverter material avoids entry into the marginal fracture as the diverter material passes by the marginal fracture without substantially entering the marginal fracture, thereby delivering at least a portion of the diverter material into the dominant fracture at least partially blocking the dominant fracture and avoiding substantial delivery of the diverter material into the marginal fracture.

Statement 24: The non-transitory computer readable medium of any one of the preceding Statements 22-23, further comprising: estimating a concentration of diverter material that enters the dominant fracture based on a transport efficiency of the diverter material in the carrier fluid, the transport efficiency being based on a difference in flow rate between the diverter material and the carrier fluid.

Claims

1. A method comprising:

determining a current flow rate distribution for fractures in a wellbore, the fractures comprising a dominant fracture and a marginal fracture, the dominant fracture receiving fluid at a higher rate from the wellbore than the marginal fracture;

determining a desired flow rate distribution for the fractures in the wellbore; and

determining a flow rate control sequence for injecting a fluid comprising a carrier fluid and a diverter material into an entrance of the wellbore at a surface of the earth to deliver the diverter material into the dominant fracture and avoid delivery of the diverter material into the marginal fracture to transition from the current flow rate distribution to the desired flow rate distribution.

2. The method of claim 1, wherein

the flow rate control sequence comprises a flow rate decrease adjustment at the entrance of the wellbore such that the diverter material enters the dominant fracture as the divert material passes by the dominant fracture and a flow rate increase adjustment at the entrance of the wellbore such that the diverter material avoids entry into the marginal fracture as the diverter material passes by the marginal fracture without substantially entering the marginal fracture, thereby delivering at least a portion of the diverter material into the dominant fracture at least partially blocking the dominant fracture and avoiding substantial delivery of the diverter material into the marginal fracture.

3. The method of claim 1 further comprising:

determining an amount of a diverter material required to at least partially block the dominant fracture to achieve the desired flow rate distribution.

4. The method of claim 1 further comprising:

estimating a concentration of diverter material that enters the dominant fracture based on a transport efficiency of the diverter material in the carrier fluid, the transport efficiency being based on a difference in flow rate between the diverter material and the carrier fluid.

5. The method of claim 4 wherein the estimating is further based on at least one member selected from the group of a perforation property, perforation orientation, and a diverter material property.

6. The method of claim 4 wherein the transport efficiency is defined by the formula: R i = C i  Q i C up  Q up

wherein Ri is transport efficiency,

Ci is the concentration of the diverter material that will enter into a fracture i,

Cup is the concentration upstream of a fracture i,

Qi is the volumetric flow rate of the diverter material into a fracture i,

Qup is the volumetric flow rate of the diverter material upstream of a fracture i,

wherein fracture i comprises at least the dominant fracture.

7. The method of claim 4, wherein the flow rate sequence comprises determining a flow rate of the diverter material upstream from the dominant fracture for delivering at least a portion of the diverter material into the dominant fracture.

8. The method of claim 7, wherein the dominant fracture is a first dominant fracture, and the wellbore further comprises a second dominant fracture, the second dominant fracture being downstream from the first dominant fracture, each of the first and second dominant fractures receiving fluid at a higher rate from the wellbore than the marginal fracture,

the determining the flow rate sequence further comprises determining a second flow rate of the fluid upstream from a second dominant fracture but downstream from the first dominant fracture for delivering at least a portion of the diverter material to the second dominant fracture at least partially blocking the second dominant fracture.

9. The method of claim 4, further comprising updating at least one of the rate control sequence or the amount of diverter material required to block the dominant fracture based on the estimated concentration of diverter material that enters the dominant fracture.

10. The method of claim 4 wherein the wellbore comprises a plurality of dominant fractures and a plurality of marginal fractures, each of the plurality of dominant fractures receiving fluid at a higher rate from the wellbore than the marginal fractures, and

the method comprising determining a rate control sequence for each of the plurality of dominant fractures and each of the plurality of marginal fractures, the rate control sequence comprising a flow rate decrease adjustment at the entrance of the wellbore such that a portion of the diverter material enters each of the plurality of dominant fractures as the diverter material passes by each of the plurality of the dominant fractures and a flow rate increase adjustment at the entrance of the wellbore such that the diverter material avoids entry into each of the marginal fractures as the diverter material passes by each of the marginal fractures.

11. The method of claim 10 wherein the dominant fractures and marginal fractures have perforations arranged in clusters, the flow rate control sequence being based on clusters of the dominant or marginal fractures.

12. The method of claim 4, further comprising determining a concentration of the diverter material injected into the entrance of the wellbore at the surface of the earth based on an effect on the concentration of the diverter as it transports from the surface to at least one of the dominant fracture or the marginal fracture.

13. The method of claim 4, further comprising determining the rate control sequence based on a translational time delay, the translational time delay comprising the time it takes for flow rate change at the entrance of the wellbore to translate to a flow rate change of the diverter material as it passes at least one of the dominant fracture or the marginal fracture in the wellbore.

14. The method of claim 4, wherein the diverter material is injected into the entrance of the wellbore at the surface by pump equipment,

the method further comprising determining the rate control sequence further based on a delay in a rate command change input to the pump equipment and a change in rate being actuated by the pump equipment to the diverter material injected at the surface.

15. The method of claim 1, wherein the diverter material is injected in the form of a pill.

16. The method of claim 1, wherein the fluid is injected by an electric pump.

17. The method of claim 1, carrying out an injection of diverter material based on the determined flow rate control sequence.

18. A system comprising:

one or more processors; and

a memory storing instructions to:

determining a desired flow rate distribution for fractures in a wellbore, the fractures comprising a dominant fracture and a marginal fracture, the dominant fracture receiving fluid at a higher rate from the wellbore than the marginal fracture; and

determining a flow rate control sequence for injecting a fluid comprising a carrier fluid and a diverter material into an entrance of the wellbore at a surface of the earth to deliver the diverter material into the dominant fracture and avoid delivery of the diverter material into the marginal fracture to achieve the desired flow rate distribution.

19. The system of claim 18 wherein

the flow rate control sequence comprises a flow rate decrease adjustment at the entrance of the wellbore such that the diverter material enters the dominant fracture as the divert material passes by the dominant fracture and a flow rate increase adjustment at the entrance of the wellbore such that the diverter material avoids entry into the marginal fracture as the diverter material passes by the marginal fracture without substantially entering the marginal fracture, thereby delivering at least a portion of the diverter material into the dominant fracture at least partially blocking the dominant fracture and avoiding substantial delivery of the diverter material into the marginal fracture.

20. The system of claim 18 further comprising:

estimating a concentration of diverter material that enters the dominant fracture based on a transport efficiency of the diverter material in the carrier fluid, the transport efficiency being based on a difference in flow rate between the diverter material and the carrier fluid.

21. The method of claim 18, further comprising determining a concentration of the diverter material injected into the entrance of the wellbore at the surface of the earth based on an effect on the concentration of the diverter as it transports from the surface to at least one of the dominant fracture or the marginal fracture.

22. A non-transitory computer readable medium storing instructions that, when executed by one or more processors, cause the one or more processors to:

determining a desired flow rate distribution for fractures in a wellbore, the fractures comprising a dominant fracture and a marginal fracture, the dominant fracture receiving fluid at a higher rate from the wellbore than the marginal fracture; and

determining a flow rate control sequence for injecting a fluid comprising a carrier fluid and a diverter material into an entrance of the wellbore at a surface of the earth to deliver the diverter material into the dominant fracture and avoid delivery of the diverter material into the marginal fracture to achieve the desired flow rate distribution.

23. The non-transitory computer readable medium of claim 22, wherein

the flow rate control sequence comprises a flow rate decrease adjustment at the entrance of the wellbore such that the diverter material enters the dominant fracture as the divert material passes by the dominant fracture and a flow rate increase adjustment at the entrance of the wellbore such that the diverter material avoids entry into the marginal fracture as the diverter material passes by the marginal fracture without substantially entering the marginal fracture, thereby delivering at least a portion of the diverter material into the dominant fracture at least partially blocking the dominant fracture and avoiding substantial delivery of the diverter material into the marginal fracture.

24. The non-transitory computer readable medium of claim 22 further comprising:

estimating a concentration of diverter material that enters the dominant fracture based on a transport efficiency of the diverter material in the carrier fluid, the transport efficiency being based on a difference in flow rate between the diverter material and the carrier fluid.