TITLE: METHOD FOR SELECTING CHOKE SIZES, ARTIFICIAL LIFT

PARAMETERS, PIPE SIZES AND SURFACE FACILITIES UNDER PRODUCTION

SYSTEM CONSTRAINTS FOR OIL AND GAS WELLS

BACKGROUND OF THE INVENTION

1. Field of the Invention

The invention generally relates to a methodology for optimizing the selection of choke and pipe sizes as well as parameters for artificial lift and surface facilities under production system constraints for oil and gas wells.

2. Description of the Relevant Art

Selection of choke and pipe sizes as well as the operation of artificial lift equipment varies significantly among operators. An improper production schedule, characterized by a rapid and excessive drawdown could trigger massive sand production or proppant flowback, possibly resulting in completion impairment and wellbore failure.

For example, previous studies on bean-up protocols and sand production have focused primarily on suggesting the maximum allowable drawdown or upper bound limits for fluid velocities in the near wellbore region, with respect to different failure mechanisms and completion types. Such recommendations are either based on rules of thumb derived from past experience, compilation of data or simple analytical models. In most instances such

generalizations are not valid since many parameters can vary from one well to another. As such, these recommendations are often incorrect and may not guarantee a successful production ramp- up.

Analytical and numerical models are currently used to determine the pressures and rates in a production system. However, such models do not consider constraints on the production system that are imposed by the potential failure of the reservoir rock, completion, wellbore or surface equipment. For instance, when sand production is a concern, the application of such models can provides an incorrect estimate for the maximum allowable drawdown since sand production can result in wellbore collapse and failure. Bringing a well on too quickly using aggressive choke management strategies may induce substantial pressure gradients capable of mobilizing the failed sand or causing direct tensile failure of the weakly consolidated formation.

Strategies for managing chokes and artificial lift equipment also vary significantly in hydraulically fractured wells and frac-pack completions. The clean-up phase is considered to be the most crucial time in the life of the well: the proppant is adjusted and packed in place, setting the foundation for short and long term productivity. Upon the completion of stimulation treatments, operators are sometimes tempted to apply aggressive drawdown schedules which may result in increased proppant back-production, reduced fracture conductivity and hence poor well performance. An abrupt decrease in bottom-hole-pressure ("BHP") can also give rise to completion stability issues, with particularly severe implications in offshore developments. In addition, the destabilization of the annular pack due to high velocities through the perforations may cause a series of operating nuances such as the plugging of screens or flowlines, the erosion of surface or downhole equipment which add to the maintenance costs and increase the likelihood of a temporary shut-in. These factors have increased the awareness of properly designing flowback procedures in order to maximize fracture conductivity and improve long term performance.

Based on the previous observations, it is desirable to adopt a systematic method for optimizing choke management, surface facilities and artificial lift equipment in order to maximize production and mitigate the risk of typical wellbore or completion failures. The method should be general enough to be applied across a range of fluids, well completions and reservoir properties

SUMMARY OF THE INVENTION

In an embodiment, a method of optimizing the management of oil and gas wells, includes: obtaining a wellbore model of the hydrocarbon subsurface formation; obtaining a reservoir model of the hydrocarbon subsurface formation; obtaining a model for surface facilities which include separators, flowlines and chokes; combining the wellbore model, surface facility model and the reservoir model to form a dynamic production system model; applying a choke model or an artificial lift model to the production system model; applying predetermined constraints to the production system model; applying criteria that define an optimized production from the hydrocarbon subsurface formation; adjusting the choke size or artificial lift parameters and determining the effect of these adjustments on production rate and bottom hole pressure;

determining a choke sequence or artificial lift operational parameters for the hydrocarbon subsurface formation which will maximize production from the hydrocarbon subsurface formation; and implementing these optimized strategies manually or with the use of computer- adjusted controls attached to the production system.

In an embodiment, the hydrocarbon subsurface formation may be a fractured formation.

In an embodiment, the choke sequence comprises a sequence of varying choke sizes over a period of time.

The method may further include applying equipment limitations to the wellbore-reservoir system model prior to determining an optimized choke sequence for the hydrocarbon subsurface formation. In an embodiment, the equipment limitations comprise one or more of the following properties: separator pressure, diameter of surface flowlines, length of surface flowlines, hydraulic roughness, maximum surface oil flow rate, maximum surface water flow rate, maximum surface gas flow rate, maximum wellhead pressure, maximum pressure downstream of choke, and minimum velocity at the wellbore.

In some embodiment, the reservoir model comprises one or more of the following properties: reservoir initial conditions, formation height, and formation fluid properties.

In some embodiments, the wellbore model comprises one or more of the following properties: well trajectory, tubing internal diameter, hydraulic roughness, and temperature.

In some embodiments, the artificial lift model comprises one or more of the following properties: location and pressure on gas lift valves, electrical submersible pump frequencies, stroke length of rod pumps, frequency of plunger and rod pumps.

In some embodiments, determining an optimized choke sequence for the hydrocarbon subsurface formation comprises determining the bottom hole pressure for different choke sizes and determining the optimal choke size that will satisfy the completion-specific failure criteria associated with the producing interval. The choke sequence may include a sequence of choke sizes and times to maintain the choke at a specific size, wherein, during production of fluid from the hydrocarbon subsurface formation, each choke size of the choke sequence is applied for the time associated with the choke size.

In some embodiments, determining optimized artificial lift parameters as a function of time for the hydrocarbon subsurface formation comprises determining the bottom hole pressure for different gas lift annular pressures, frequency of electrical submersible pumps, rod pumps or plunger lifts that will satisfy the completion-specific failure criteria associated with the producing interval or other constraints placed on the production system.

In an embodiment, a method of optimizing choke management for oil and gas wells, includes: obtaining a wellbore model of the hydrocarbon subsurface formation; obtaining a reservoir model of the hydrocarbon subsurface formation; obtaining a model for surface facilities which include separators, flowlines and chokes; combining the wellbore model, surface facility model and the reservoir model to form a dynamic production system model; applying an artificial lift model to the production system model; applying one or more predetermined constraints to the production system model; applying criteria that define an optimized production from the hydrocarbon subsurface formation; adjusting the artificial lift equipment and determining the effect on production rate and bottom hole pressure; determining optimized artificial lift operating parameters for the hydrocarbon subsurface formation which will maximize production from the hydrocarbon subsurface formation; and implementing the optimized artificial lift parameters with the use of a manually adjusted or computer-adjusted controls.

In some embodiments, determining optimized surface facilities as a function of time for the hydrocarbon subsurface formation comprises determining the separator pressure, the diameter of the surface flow lines, the location, setting and operation of valves connecting the flow lines that will satisfy the completion-specific failure criteria associated with the producing interval or other constraints placed on the production system.

In an embodiment, a method of optimizing surface facilities in oil and gas wells, comprising: obtaining a wellbore model of the hydrocarbon subsurface formation; obtaining a reservoir model of the hydrocarbon subsurface formation; obtaining a model for surface facilities which include separators, flowlines and chokes; combining the wellbore model, surface facility model and the reservoir model to form a dynamic production system model; applying one or more predetermined constraints to the production system model; applying criteria that define an optimized production from the hydrocarbon subsurface formation; determining optimized operational parameters for the surface facilities for the hydrocarbon subsurface formation which will maximize production from the hydrocarbon subsurface formation; and implementing the optimized operational parameters for the surface facilities manually or with the use of computer- adjusted controls.

BRIEF DESCRIPTION OF THE DRAWINGS

Advantages of the present invention will become apparent to those skilled in the art with the benefit of the following detailed description of embodiments and upon reference to the accompanying drawings in which:

FIG. 1 depicts a schematic diagram of a reservoir model;

FIG. 2 depicts a typical graph of IPR and VLP;

FIG. 3 depicts an exemplary comparison of VLP for various choke sizes compared to the IPR;

FIG. 4 depicts a logical diagram of the method of optimizing the choke size for a well using a set of user specified completion criteria;

FIG. 5 depicts a schematic diagram of how the method works over an extended time period; FIG. 6 depicts a graph showing that for a choke size of 2/64" the VLP does not intersect the IPR curve;

FIG. 7 depicts an optimized choke sequence;

FIG. 8 depicts the effect of the choke sequence depicted in FIG. 7 on oil rate;

FIG. 9 depicts depict the effect of the choke sequence depicted in FIG. 7 on perforation velocity;

FIG. 10 depicts the effect of the choke sequence depicted in FIG. 7 on completion drawdown; FIG. 11 depicts an IPR vs. VLP comparison for various choke sizes in a cased-hole well with a high permeability;

FIG. 12 depicts an optimized choke sequence for a cased-hole well with a high permeability; FIG. 13 depicts the effect of the choke sequence depicted in FIG. 12 on oil rate;

FIG. 14 depicts the effect of the choke sequence depicted in FIG. 12 on perforation velocity; FIG. 15 depicts the effect of the choke sequence depicted in FIG. 12 on completion drawdown; FIG. 16 depicts the effect of changing the permeability of the model on choke sequence and perforation velocity;

FIG. 17 depicts an IPR vs. VLP comparison for various choke sizes for the design of a clean-up operation in an unconventional oil well;

FIG. 18A depicts the optimum choke sequence versus time for the design of a clean-up operation in an unconventional oil well;

FIG 18B shows the equilibrium BHP for the corresponding choke size for the choke sequence of FIG. 18 A;

FIG. 18C depicts the effect of the choke sequence of FIG. 18A on oil/water rate;

FIG. 18D depicts the effect of the choke sequence of FIG. 18A on confining stress along the fracture;

FIG. 18E depicts the effect of the choke sequence of FIG. 18A on the pressure gradient along the fracture;

FIG. 19 depicts the IPR and VLP curves for a reservoir/production system having very high porosity at initial conditions;

FIG. 20A depicts the optimum choke sequence for a reservoir/production system having very high porosity;

FIG. 20 B depicts the effect of the choke sequence of FIG. 20 A on bottom hole pressure (BHP); FIG. 20C depicts the effect of the choke sequence of FIG. 20 A on production rate;

FIG. 20D depicts the effect of the choke sequence of FIG. 20 A on perforation pressure drop; FIG. 20E depicts the effect of the choke sequence of FIG. 20A on perforation velocity; and FIG. 20F depicts the effect of the choke sequence of FIG. 20A on annular velocity.

While the invention may be susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but to the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

It is to be understood the present invention is not limited to particular devices or methods, which may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used in this specification and the appended claims, the singular forms "a", "an", and "the" include singular and plural referents unless the content clearly dictates otherwise. Furthermore, the word "may" is used throughout this application in a permissive sense (i.e., having the potential to, being able to), not in a mandatory sense (i.e., must). The term "include," and derivations thereof, mean "including, but not limited to." The term "coupled" means directly or indirectly connected.

The following description generally relates to systems and methods for optimizing the production of hydrocarbons from formations. Such formations may be treated to yield hydrocarbon products and other products.

A "fluid" may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.

A "formation" includes one or more hydrocarbon containing layers, one or more non- hydrocarbon layers, an overburden, and/or an underburden. "Hydrocarbon layers" refer to layers in the formation that contain hydrocarbons. The hydrocarbon layers may contain non- hydrocarbon material and hydrocarbon material. The "overburden" and/or the "underburden" include one or more different types of impermeable materials. For example, the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate.

"Formation fluids" refer to fluids present in a formation and may include gases and liquids produced from a formation. Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids. Examples of formation fluids include inert gases, hydrocarbon gases, carbon oxides, mobilized hydrocarbons, water (steam), and mixtures thereof. The term

"mobilized fluid" refers to fluids in a hydrocarbon containing formation that are able to flow as a result of thermal treatment of the formation. "Produced fluids" refer to fluids removed from the formation.

"Fracture" refers to a crack or surface of breakage within a rock. A fracture along which there has been lateral displacement may be termed a fault. When walls of a fracture have moved only normal to each other, the fracture may be termed a joint. Fractures may enhance

permeability of rocks greatly by connecting pores together, and for that reason, joints and faults may be induced mechanically in some reservoirs in order to increase fluid flow. "Hydrocarbons" are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltenes.

Hydrocarbons may be located in or adjacent to mineral matrices in the earth. Matrices may include, but are not limited to, sedimentary rock, sands, sandstones, silicilytes, limestones, dolomites, shales, carbonates, diatomites, and other porous media. "Hydrocarbon fluids" are fluids that include hydrocarbons. Hydrocarbon fluids may include, entrain, or be entrained in non-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia.

"Hydraulic fracturing" refers to creating or opening fractures that extend from the wellbore into formations. A fracturing fluid, typically viscous, may be injected into the formation with sufficient hydraulic pressure (for example, at a pressure greater than the lithostatic pressure of the formation) to create and extend fractures, open preexisting natural fractures, or cause slippage of faults. In the formations discussed herein, natural fractures and faults may be opened by pressure. A proppant may be used to "prop" or hold open the fractures after the hydraulic pressure has been released. The fractures may be useful for allowing fluid flow, for example, through a shale formation, or a geothermal energy source, such as a hot dry rock layer, among others.

The term "wellbore" refers to a hole in a formation made by drilling or insertion of a conduit into the formation. A wellbore may have a substantially circular cross section, or another cross-sectional shape. The wellbore may be open-hole or may be cased and cemented. As used herein, the terms "well" and "opening," when referring to an opening in the formation may be used interchangeably with the term "wellbore." "Horizontal wellbore" refers to a portion of a wellbore in a subterranean hydrocarbon containing formation to be completed that is substantially horizontal or deviated at an angle from horizontal in the range of from about 0° to about 15°.

The term facilities refers to the flow lines, valves and separators that are used to process, store and control the flow of fluids from the subsurface formation.

Different production management strategies have been adopted by operators in the field.

However, no general method exists for systematically selecting an optimum choke and artificial lift management strategy when one or more constraints are imposed on the system. Strategies of stepwise choke setting adjustments appear to produce the best production from a well. In one embodiment, bottom-hole pressure ("BHP") adjustments are determined using a wellbore- reservoir model of a formation for wells operating under different choke settings. An optimum production management strategy is determined based on predetermined criteria. For example, a choke management strategy can be devised using the anticipated formation damage mechanisms.

For example, if fines migration and sand production are a concern, then minimizing the near wellbore pressure gradients is the primary criterion for the selection of the optimum choke management strategy. In hydraulically fractured wells, choke management strategies should aim towards minimizing pressure gradients along the fracture, thus making proppant flowback and potential reduction/loss of fracture conductivity or its connectivity to the wellbore less likely to occur, for a given set of formation properties and closure stress.

The purpose of the method is to maximize well productivity and prevent damage to the well completion or to the reservoir through proper production system management. For example, through dynamic nodal analysis the method can suggest whether a choke size can be used or whether that particular choke size is too small or too big for a user-specified wellbore-reservoir system operating under user specified constraints. The model is based on the notion of dynamically coupling a reservoir model to a wellbore model in order to select the optimum choke sequence (choke size versus time) that will satisfy the various completion/reservoir/rate constraints while, at the same time, maximizing production rates.

The method comprises five primary entities: a reservoir model, a completion model, a wellbore model and a model for the surface facilities including the choke and a model for artificial lift, if such equipment is installed. The five models are coupled together to ensure that the pressures and rates are continuous going from the reservoir all the way to the separator. This integration, as used herein, is called "dynamic nodal analysis" to reflect the fact that it is time dependent. This approach may be used to select the choke sequence, artificial lift operational parameters and the operation of surface facilities as a function of time while respecting certain criteria (such as max completion pressure drop etc.).

The reservoir model is a model of the formation itself. The reservoir model includes formation properties, fluid properties and reservoir conditions. Formation properties include, but are not limited to: permeability, porosity, relative permeability and total compressibility for each geological layer. Fluid properties include, but are not limited to, fluid type (gas or liquid), pressure-volume-temperature relationships, and fluid viscosity. The reservoir conditions are the conditions of the formation at any given time (e.g., pressure and saturation spatial distribution). Most of the initial properties of a reservoir are known before production of fluids begins from the formation and can be entered into a model. The reservoir model also includes algorithms for altering the reservoir conditions based on projected fluid flow from the reservoir. A schematic diagram of a reservoir model is depicted in FIG. 1. The reservoir model provides the transient fluid flow rates versus bottom-hole-pressure. The reservoir model provides the rates (oil rate, gas rate, water rate, water-oil ratio, gas-liquid ratio) necessary to be used with a wellbore model. The reservoir model can be updated with the current reservoir conditions in order to provide an updated estimate for the transient flow rates.

The wellbore model is a model of the wellbore. The wellbore model takes into account parameters such as multi-phase flow in the wellbore, the presence of any constrictions or annuli in the wellbore. The model for the surface facilities includes models for multi-phase flow in the surface flowlines, the separator and the choke. Specific features that are used to model the wellbore include, but are not limited to, well trajectory, tubing internal diameter, hydraulic roughness, temperature. For most production sites, the wellbore model parameters are substantially unchanged during production, with the exception of the choke diameter.

For a given set of production rates (e.g., oil rate, water rate, gas rate, GLR, WOR), surface equipment (e.g., separator pressure, diameter and length of surface flowlines, hydraulic roughness) and wellbore properties (e.g., well trajectory, tubing internal diameter, hydraulic roughness, temperature) the wellbore model provides the bottom-hole pressure (BFIP) from the separator side. The BFIP is calculated by adding the frictional pressure losses and the hydrostatic head associated with each element present in the production system. Depending on the fluid system (water-oil-gas system or gas-water system) an appropriate choke model may be used.

BHP(Q) = Psep + APflowlines(Q) + APchoke(Q) + APwell(Q) + Hydrostatic

The rates for different BHP are calculated from the reservoir side using a reservoir simulator and a completion model. When this BHP is equal to the BHP calculated from the wellbore model the system is in equilibrium and the solution for the well BHP and well rates is obtained. Various choke flow models may be found in the following references, all of which are incorporated herein by reference: Achong, L, "Revised Bean Performance Formula for Lake Maracaibo Wells", internal co. report, Shell Oil Co., Houston, TX, Oct 1961; Ashford et al. "Determining Multiphase Pressure Drops and Flow Capacities in Down-Hole Safety Valves", SPE Paper No. 5161, J. Pet. Tech., Sep 1975, 1145; Baxendell, P.B., "Bean Performance - Lake Maracaibo Wells", internal co. report, Shell Oil Co., Houston, TX, Oct 1967; Gilbert, W.E., "Flowing and Gas-Lift Well Performance", Drill. & Prod. Practice, 1954, 126; Omana et al., "Multiphase Flow Through Chokes", SPE Paper No. 2682, paper presented at Annual Fall Meeting of the SPE of AFME, Denver, CO, Sep 28 - Oct 1, 1969; and Ros, N.C.J., "An Analysis of Critical Simultaneous Gas-Liquid Flow Through a Restriction and Its Application to Flow metering", Appl. Sci. Res. (9), 1960, 374.

In an embodiment of the method, a graphical method is used for performing the nodal analysis. Before the nodal analysis is begun neither the BHP or production rate is known. The method includes constructing a transient inflow performance relationship ("IPR") using the reservoir model. The IPR is a plot of the well production rate against the flowing bottom hole pressure (BHP). The data required to create the transient IPR is obtained by using the reservoir model to determine the production rates under various drawdown pressures. The reservoir fluid composition and behavior of the fluid phases under flowing conditions determine the shape of the curve.

The method also includes preparing a transient vertical lift performance ("VLP") curve using the wellbore model. The VLP is constructed using the gas-oil ratio ("GOR"), water-oil ratio ("WOR") and other parameters provided by the reservoir model. A typical graph of IPR and VLP is shown in FIG. 2. The nodal analysis provides the BHP for which the reservoir model (IPR curve) and wellbore model (VLP curve) are in equilibrium/operate in tandem.

During nodal analysis of the system, a plurality of VLP curves can be constructed for each choke size and artificial lift system. FIG. 3 depicts an exemplary comparison of VLP for various choke sizes. During optimization of the choke sequence, choke sizes that cannot ensure equilibrium between the reservoir (IPR) and wellbore models (VLP) are excluded. For instance, if a particular choke is too small the well will not flow and that choke needs to be excluded from the list of candidate choke sizes. In the example shown in FIG. 3, choke sizes of 2/64", 4/64", 6/64" do not intersect the transient Inflow Performance Relationship and are thus be excluded from the list of candidate choke sizes.

The method also includes adding completion constraints information to the model, so that the choke size can be optimized for the particular producing formation. The completion constraints depend on the wellbore and the completion properties. The completion constraints may depend on many factors including, but not limited to the formation properties and the completion type.

For an open-hole production system the completion properties include, but are not limited to: perforated interval, gravel pack permeability, skin factor and pressure gradient dependent permeability. The choke selection criteria for an open-hole production system may be defined by constraints that include, but are not limited to: annular fluid velocity, C-factor (kinetic energy), pressure gradient, total drawdown and pressure drop across completion. For a cased-hole production system the completion properties include, but are not limited to: perforated interval, perforation density, perforation diameter, and % of active perforations. The choke selection criteria for a cased-hole production system may be defined by constraints that include, but are not limited to: perforation velocity, C-factor (kinetic energy), annular velocity, pressure gradient, and pressure drop across completion.

For a frac-pack production system the completion properties include, but are not limited to: facture width, fracture length, and gravel permeability. The choke selection criteria for a frac- pack production system may be defined by constraints that include, but are not limited to: C- factor (kinetic energy), annular velocity, perforation velocity, total drawdown, and oil/water rate. For a hydraulically fractured production system the completion properties include, but are not limited to: facture width, fracture length, spacing, in-situ stresses and proppant strength. The choke selection criteria for a hydraulically fractured production system may be defined by constraints that include, but are not limited to: fracture pressure gradient, total drawdown, oil/water rate, proppant crushing, and closure of unpropped fractures.

The method allows a user to select the criteria that are important to the particular producing formation and/or well completion. The selected criteria allow the software to create an optimized choke selection sequence that is customized for the particular well and/or production formation.

FIG. 4 depicts a logical diagram of the method of optimizing the choke size for a well using a set of user specified completion criteria. Initially, at a time (tl) the state of the reservoir is obtained from the reservoir model. A choke size is then selected and the nodal equilibrium for the particular choke size selected is performed using the wellbore, completion and choke models. Updated reservoir conditions are then determined from the reservoir model. The updated reservoir conditions are used to determine if the user selected criteria have been met. If the criteria have been met, the method increases the choke size and the process is repeated. If the criteria are not met, the method reverts to the last choke size that met the criteria.

After a predetermined amount of time elapses (ΔΤ), the method restarts by determining the reservoir state assuming that production has been run for the predetermined time at the selected choke size. FIG. 5 depicts a schematic diagram of how the method works over an extended time period. At the beginning of every time step (A, B, C, D) the nodal analysis is performed and the equilibrium BHP is used for simulating the reservoir for that particular time step. In order to reduce simulation time, the method may test the applicability of a larger choke size at specific times (A and D) (i.e. skipping time steps B and C where nodal equilibrium is performed without checking the applicability of a larger choke setting). In an exemplary application, the production system is a cased-hole well with a low permeability. The following parameters were entered into the nodal analysis:

Reservoir Properties

Permeability - 50md

Porosity - 0.25

Formation Height - 100 ft.

Initial Sw/So - 0.3/0.7

Wellbore Properties

Separator - 60 psi

Surface Flowline - 1.5", 120 ft.

Production Tubing - 2.943"; 10,000 ft.

Wellbore Model - Friction Factor

Failure Criteria

Perforation Velocity - 8ft/sec

Completion Drawdown - 400 psi

Choke Sizes tX/64")

2/64" to 44/64"

Increments of 2/64"

The IPR vs. VLP comparison, depicted in FIG. 6 shows that for a choke size of 2/64" the VLP does not intersect the IPR curve, and thus this size is excluded from the nodal analysis. Using the methodology presented in FIGS. 4 and 5, an optimized choke sequence can be developed and is depicted in FIG. 7. The choke sequence depicted in FIG. 7 is the choke sequence which gives optimized production based on the failure criteria selected by the user. In this case, the choke sequence ensures that production is maximized while ensuring that neither of the failure criteria are violated during production. The model suggests the optimum choke sequence versus time (upper chart). For these particular reservoir properties, a choke size of 22/64" should be used for 12 hours, a 28/64" choke should be used for the next 12h, etc. The chart in the bottom shows the equilibrium BHP for the corresponding choke size. FIGS. 8-10 depict the effect of the choke sequence depicted in FIG. 7 on oil rate, perforation velocity and completion drawdown, respectively. In FIG. 10, the chart in the bottom presents the actual completion drawdown (one of the two failure criteria) versus time relative to the critical value of that criterion (red line). The method ensures that the criterion is met (i.e. actual values are lower than the critical value) while at the same time production rates are maximized (largest compatible choke size being used). For this particular example, the completion drawdown proves to be the crucial criterion that determines the optimum choke sequence.

In another exemplary application, the production system is a cased-hole well with a high permeability. The following parameters were entered into the dynamic nodal analysis:

Reservoir Properties

Permeability - 750md

Porosity - 0.25

Formation Height - 100 ft.

Initial Sw/So - 0.3/0.7

Wellbore Properties

Separator - 60 psi

Surface Flowline - 1.5", 120 ft.

Production Tubing - 2.943"; 10,000 ft.

Wellbore Model - Friction Factor

Failure Criteria

Perforation Velocity - 8ft/sec

Completion Drawdown - 400 psi

Choke Sizes (X/64")

6/64" to 44/64"

Increments of 2/64"

The IPR vs. VLP comparison, depicted in FIG. 11 shows that for a choke size of 10/64" or less the VLP does not intersect the IPR curve, and thus sizes of 10/64" or lower should be excluded from the nodal analysis. Using the methodology presented in FIGS. 4 and 5, an optimized choke sequence can be developed and is depicted in FIG. 12. The choke sequence depicted in FIG. 12 is the choke sequence which gives optimized production under the constraints or failure criteria provided by the user. In this case, the choke sequence ensures that production is maximized while ensuring that neither of the failure criteria are violated during production. The model specifies the optimum choke sequence versus time (upper chart). The chart at the bottom of the figure shows the equilibrium BHP for the corresponding choke size. FIGS. 13-15 depict the effect of the choke sequence depicted in FIG. 12 on oil rate, perforation velocity and completion drawdown, respectively. FIG. 16 depicts the effect of changing the permeability of the model on choke sequence and perforation velocity;

In another exemplary application, the method is deployed for the design of a clean-up operation in an unconventional oil well. The following parameters were entered into the dynamic nodal analysis:

Reservoir Properties

Permeability - 200nd

Porosity - 0.05

Formation Height - 250 ft.

Initial Sw/So - 0.2/0.8

Fracture Properties

Half-Length - 200 ft.

Spacing - 175 ft.

Conductivity - 200 md-ft.

Number of fractures - 60

Initial Sw/So - 0.95/0.05

Wellbore Properties

Separator - 60 psi

Surface Flowline - 3", 300 ft.

Production Tubing - 3.6"; 9,800 ft.

Wellbore Model - Friction Factor

Failure Criterion

Proppant flowback equal or lesser than 30% of the proppant mass initially in place:

(dp/dr) _MAX < 100 log(o') - 250

(this equation was obtained using the numerical results from Shor, R. and Sharma M. M. "Reducing Proppant Flowback From Fractures: Factors Affecting the Maximum

Flowback Rate", Paper SPE 168649 presented at the Hydraulic Fracturing Technology Conference, The Woodlands, TX, 4-6 February 2014)

Choke Sizes tX/64")

6/64" to 128/64"

The IPR vs. VLP comparison, depicted in FIG. 17 shows that for a choke size of 12/64" or less the VLP does not intersect the IPR curve, and thus this sizes of 2/64" or lower should be excluded from the nodal analysis. Using the methodology presented in FIGS. 4 and 5, an optimized choke sequence can be developed and is depicted in FIG. 18. The choke sequence depicted in FIG. 18A is the choke sequence which gives optimized production based on the failure criteria selected by the user. In this case, the choke sequence ensures that production is maximized while ensuring that pressure gradients along the fracture do not exceed the maximum allowable value dictated by the in situ effective stress (FIG. 18E). The model suggests the optimum choke sequence versus time (FIG. 18 A). FIG 18B shows the equilibrium BFTP for the corresponding choke size. FIGS. 18C-18E depict the effect of the choke sequence on oil/water rate, confining stress and pressure gradient along the fracture, respectively.

In another example a vertical cased-hole well having a very high permeability was studied to find the choke management strategy that satisfies a set of constraints for a given formation and production system. The properties of the system are presented in Table 1. The well is subject to the constraints shown in Table 2. It is important to note that we do not know, a priori, which of the three constraints will be crucial in the selection of choke size as a function of time.

FIG. 19 presents the IPR and VLP curves for the reservoir/ production system at initial conditions. The smallest choke size that may be used is 12/64" . The choke selection algorithm was run for this case and the recommended choke management strategy, along with the full profile of the operation are presented in FIGS. 20A-F. At t=0, instead of using the smallest compatible diameter (12/64"), the algorithm selects the largest choke diameter (26/64") that satisfies all three constraints placed on the system. Comparing FIGS. 20 D, E, and F we observe that, for this particular case, perforation velocity is the crucial factor that determines the choke size as a function of time.

Specific details regarding the implementation and algorithms that can be used to understand the fundamental basis for the effect of varying choke sizes on the completion criteria may be found in the following papers, both of which are incorporated herein by reference:

Karantinos, E., M. M. Sharma "Choke Management under Wellbore, Completion and Reservoir Constraints", SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 09-11, 2017, Society of Petroleum Engineers, 10/2017; Karantinos, E., M. M. Sharma, J. A. Ayoub, and M. Parlar, "Choke Management Strategies for Hydraulically Fractured Wells and Frac-Pack Completions in Vertical Wells", SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, U.S.A., February 24-26, 2016, Society of Petroleum Engineers, 02/2016 and Karantinos, E., M. M. Sharma, J. A. Ayoub, M. Parlar, and R. A. Chanpura, "A General Method for the Selection of an Optimum Choke Management

Strategy", SPE European Formation Damage Conference and Exhibition, Budapest, Hungary, June 03-05, 2015, Society of Petroleum Engineers, 06/2015. (1200KB) (384.15 KB) (375.25 KB).

In addition to adjusting the choke size, this method can be used in a similar manner to adjust the separator pressure, valve settings and make changes to the artificial lift system to ensure that all the constraints imposed on the production system are satisfied. For example, the frequency of an electrical submersible pump can be changed to increase liquid production and decrease bottom-hole pressure. Similarly, the pressure in the separator can be decreased to decrease the pressure on the wellhead and choke and allow more fluids to be produced. Other examples of adjustments that can be made include, but are not limited to, changing the size of the tubing and flow lines, adjusting the annular pressure in the gas lift system, changing the frequency of the plunger lift system, altering the stroke length and frequency of rod pumps. The method proposed here can be used to determine how each of these changes will impact the pressures and flow rates at every location in the production system to ensure that all the constraints are satisfied.

The method may be implemented on a computer system. Computer systems may, in various embodiments, include components such as a CPU with an associated memory medium such as Compact Disc Read-Only Memory (CD-ROM). The memory medium may store program instructions for computer programs. The program instructions may be executable by the

CPU. Computer systems may further include a display device such as monitor, an alphanumeric input device such as keyboard, and a directional input device such as mouse. Computer systems may be operable to execute the computer programs to implement computer-implemented systems and methods.

A computer system may allow access to participants by way of any browser or operating system. Computer systems may include a memory medium on which computer programs according to various embodiments may be stored. The term "memory medium" is intended to include an installation medium, e.g., Compact Disc Read Only Memories (CD-ROMs), a computer system memory such as Dynamic Random Access Memory (DRAM), Static Random Access Memory (SRAM), Extended Data Out Random Access Memory (EDO RAM), Double Data Rate Random Access Memory (DDR RAM), Rambus Random Access Memory (RAM), etc., or a non-volatile memory such as a magnetic media, e.g., a hard drive or optical storage. The memory medium may also include other types of memory or combinations thereof. In addition, the memory medium may be located in a first computer, which executes the programs or may be located in a second different computer, which connects to the first computer over a network. In the latter instance, the second computer may provide the program instructions to the first computer for execution. A computer system may take various forms such as a personal computer system, mainframe computer system, workstation, network appliance, Internet appliance, personal digital assistant ("PDA"), "smart phone", television system or other device. In general, the term "computer system" may refer to any device having a processor that executes instructions from a memory medium.

The memory medium may store a software program or programs operable to implement embodiments as described herein. The software program(s) may be implemented in various ways, including, but not limited to, procedure-based techniques, component-based techniques, and/or object-oriented techniques, among others. For example, the software programs may be implemented using ActiveX controls, C++ objects, JavaBeans, Microsoft Foundation Classes (MFC), browser-based applications (e.g., Java applets), traditional programs, or other technologies or methodologies, as desired. A CPU executing code and data from the memory medium may include a means for creating and executing the software program or programs according to the embodiments described herein.

Various embodiments may also include receiving or storing instructions and/or data implemented in accordance with the foregoing description upon a carrier medium. Suitable carrier media may include storage media or memory media such as magnetic or optical media, e.g., disk or CD-ROM, as well as signals such as electrical, electromagnetic, or digital signals, may be conveyed via a communication medium such as a network and/or a wireless link.

In some embodiments, the method may be implemented on a computer system that is coupled to a choke of a production system. After determining the optimal choke sequence, the computer system may automatically implement the choke sequence by providing control signals that cause the choke diameter to be adjusted to the choke size required by the optimized choke sequence. The computer system may also monitor the time so that the choke size may be adjusted according to the optimized choke sequence. In an embodiment, a computer system may be incorporated into a choke controller that can operate on the choke through onsite or remote hardware or software control. The computer system may determine the optimized choke sequence and, through the choke controller, implement the optimized choke sequence during production.

In this patent, certain U.S. patents, U.S. patent applications, and other materials (e.g., articles) have been incorporated by reference. The text of such U.S. patents, U.S. patent applications, and other materials is, however, only incorporated by reference to the extent that no conflict exists between such text and the other statements and drawings set forth herein. In the event of such conflict, then any such conflicting text in such incorporated by reference U.S. patents, U.S. patent applications, and other materials is specifically not incorporated by reference in this patent.

Further modifications and alternative embodiments of various aspects of the invention will be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as examples of embodiments.

Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims.