Drilling of multilateral wells in reservoirs

Abstract

Disclosed are methods, systems, and computer-readable media to perform operations including: building a multi-layer transient model representing the reservoir based on a geological model; determining a location at the reservoir for placing the at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model; determining a well length for each lateral section of the multilateral well based on a second PI in at least one third simulation scenario executed by the multi-layer transient model; and drilling the multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

Description

TECHNICAL FIELD

[0001] This disclosure relates generally to hydrocarbon exploration, drilling, and production, and more particularly, drilling of multilateral wells in reservoirs.BACKGROUND

[0002] Multilateral wells can be used for the production of oil and gas from hydrocarbon reservoirs. Multilateral wells involve drilling multiple branches from a single main wellbore. A multilateral well includes a main wellbore and lateral sections. The main wellbore is a primary vertical or horizontal well from which multiple lateral branches extend. Lateral sections are additional branches or secondary wellbores that extend from the main wellbore to access different parts of a reservoir.BRIEF DESCRIPTION OF THE FIGURES

[0003] FIG. 1 illustrates a multilateral well, intersecting different subsurface reservoir layers for the production of oil, according to some implementations.

[0004] FIG. 2 illustrates an example process of commercial development of a hydrocarbon field, according to some implementations.

[0005] FIG. 3 illustrates an example process of determining an optimized location and optimized geometrical parameters to drill a multilateral well in a reservoir, according to some implementations.

[0006] FIG. 4 illustrates the transformation of a geological model to a transient model, according to some implementations.

[0007] FIG. 5 illustrates an example multilateral well placed on a multi-layer transient model 504 representing a reservoir.

[0008] FIG. 6 illustrates multiple locations for drilling a multilateral well, according to some implementations.

[0009] FIG. 7 illustrates pressure response and production rate when drilling a multilateral well at proposed location, according to some implementations.

[0010] FIG. 8 illustrates pressure response and production rate when drilling a multilateral well at location, according to some implementations.

[0011] FIG. 9 illustrates different lateral configurations of lateral sections in a heterogeneous reservoir, according to some implementations.

[0012] FIG. 10 illustrates a productivity index (PI) graph with respect to lateral spacings for different lateral configurations, according to some implementations.

[0013] FIG. 11 illustrates a PI graph with respect to lateral lengths, according to some implementations.

[0014] FIG. 12 illustrates a pressure response graph at producer well with respect to injector-to-producer spacings, according to some implementations.

[0015] FIG. 13 illustrates another example process of determining an optimized location and optimized geometrical parameters to drill a multilateral well in a reservoir, according to some implementations.

[0016] FIG. 14 illustrates hydrocarbon production operations that include both one or more field operations and one or more computational operations, which exchange information and control exploration for the production of hydrocarbons, according to some implementations.

[0017] FIG. 15 is a schematic illustration of an example controller (or control system) that enables an example system to detect water leaks / loss and recommend corrective repair actions, according to some implementations.DETAILED DESCRIPTION

[0018] This disclosure describes methods and systems for geometrical optimization of a multilateral well and placement of the multilateral well in a reservoir, using a transient model. Geometrical parameters of the multilateral well can include a lateral spacing between lateral sections of the multilateral well, a configuration (the number of lateral sections), a drilled length of each lateral section, and a spacing between a nearby injector (e.g., water / gas injection well) and the multilateral well. Geometrical optimization of the multilateral well refers to drilling the multilateral well (with optimal lateral spacing, configuration, and drilled length) at an optimal location of the reservoir to maximize productivity index (PI) and hydrocarbon drainage by the multilateral well.

[0019] The transient model represents a reservoir and is constructed based on reservoir data (e.g., geological data, geophysical data, petrophysical data, pressure, volume and temperature (PVT) data, reservoir initial conditions, fluid-contact data (e.g., gas-oil contact, oil-water contact), reference point, capillary pressure, relative permeability) and well data (e.g., a proposed multilateral well trajectory, an injection well trajectory, and target production rates). The transient model represents a reservoir in simulation scenarios that are iteratively performed to determine the location of a multilateral well, a configuration of the multilateral well, lateral spacing between lateral sections, the length of each lateral section, and a spacing between the multilateral well and an injection well. The productivity index (PI) is calculated to determine the optimal configuration of a multilateral well in terms of the number of lateral sections, lateral spacing, and lengths of lateral sections.

[0020] The placement of a multilateral well in a hydrocarbon reservoir can facilitate minimizing the nominal number of wells in a hydrocarbon field while maximizing the contact of the intersecting well with the hydrocarbon reservoir. The greater reservoir contact of the multilateral well with a subsurface reservoir boosts the recovery of hydrocarbons with a superior sweep efficiency, compared to a conventional single-lateral, vertical or horizontal well. Drilling multiple branches (multiple lateral sections) of a well into a reservoir from a main or mother wellbore offers potential benefits in terms of improving drainage and productivity. The mother wellbore conveys fluids to or from the surface of the multilateral well. The multiple lateral sections can promote optimal sweeping of hydrocarbon out of the reservoir to maximize the recovery of hydrocarbon.

[0021] FIG. 1 illustrates a multilateral well 100, intersecting different subsurface reservoir layers for the production of oil, according to some implementations. The multilateral well 100 includes two or more lateral sections L1, L2, L3 drilled from a common trunk or main bore 102. The lateral sections L1, L2, L3 can be horizontal, vertical, or deviated. The lateral sections L1, L2, L3 can be in the same planes, or in different planes of reservoir 110. The lateral sections L1, L2, L3 are connected to the surface of the multilateral well 100 via main bore 102. Kickoff point 104 is the location where the lateral section L2 gets separated from the main bore 102. Kickoff point 106 is the location where the lateral section L3 gets separated from the main bore 102. The black portions (e.g., included in dotted rectangle 108) of the lateral sections L1, L2, L3 represent the corresponding perforated or open-hole intervals that have intersected the reservoir 110. These perforated or open hole intervals receive the drained fluid from the intersected reservoir 110, and convey the drained fluid to the surface of the multilateral well 100 through production strings.

[0022] FIG. 2 illustrates an example process 200 of commercial development of a hydrocarbon field, according to some implementations. The example process 200 includes exploration of a hydrocarbon field 202, appraisal of the hydrocarbon field 204, hydrocarbon field development 206, oil production 208, and abandonment of the hydrocarbon field 210. The geometrical optimization of a multilateral well in this disclosure is included in the hydrocarbon field development 206.

[0023] The geometrical optimization of a multilateral well in this disclosure enables multiple local optimizations to be performed iteratively around a main wellbore to place lateral sections and determine the number of lateral sections required to meet a production target. The geometrical optimization can manage and optimize the competition among the lateral sections and maximize the drainage area, thereby increasing the well productivity index or injectivity index. With different geometrical parameter settings of a multilateral well, a well productivity index is calculated for each setting to assess the performance of the well quantitatively. A productivity index graph including all the well productivity indices for different settings is generated. Graphical presentation of the productivity indices can track, guide, and decide on the optimal geometrical parameters of a multilateral well.

[0024] In some implementations, the geometrical optimization of a multilateral well is performed using a transient model. The transient model provides a platform for hosting a reservoir with geological structures and reservoir properties. The transient model also hosts at least one multilateral well with well properties (such as well trajectories, lengths of lateral sections, lateral spacing, the number of lateral sections, a spacing between the multilateral well and an injection well) for calculating productivity indices. Additionally, reservoir heterogeneity and interference among the lateral sections can also impact the productivity of the multilateral well.

[0025] In some implementations, if the spacing between multilateral sections is too small, the drainage area of the multilateral sections may overlap, which can impact the well productivity negatively. If the spacing between the lateral sections is too large, the multilateral well may not be able to sweep the reservoir efficiently. The disclosed techniques in this disclosure strike a balance between the drainage area and the inherent interference among the lateral sections.

[0026] The disclosed techniques can enable persons skilled in the art to determine the optimal geometrical parameters of a multilateral well, such as the number of lateral sections, lateral spacing, and lengths of lateral sections. The optimal geometrical parameters can maximize a productivity index, so that the additional productivity outweighs the costs of investment in the multilateral well.

[0027] FIG. 3 illustrates an example process 300 of determining an optimized location and optimized geometrical parameters to drill a multilateral well in a reservoir, according to some implementations. Process 300 is described as being performed by a computing device including one or more processors or a controller, such as controller 1500 of FIG. 15. The example process 300 shown in FIG. 3 can be modified or reconfigured to include additional, fewer, or different steps (not shown in FIG. 3), which can be performed in the order shown or in a different order.

[0028] The example process 300 can be divided into three subprocesses 300A, 300B, and 300C. The subprocess 300A is directed to building a transient model. The subprocess 300B is directed to the preparation, execution, verification, analysis, and selection of the optimal or acceptable geometrical parameters of a multilateral well. The subprocess 300C is directed to determining injector-to-producer spacing (a distance between an injector well and the multilateral well).Subprocess 300A

[0029] The input of the transient model built in the subprocess 300A can include reservoir properties including reservoir geology and engineering properties of rocks and well properties at different locations including the respective trajectories, historical production rates, and reservoir pressures. The output of the transient model can include, for example, simulated pressure responses under well-flowing and shut-in conditions, etc.

[0030] In some implementations, the transient model is built based on a geological model. The geological model is a computerized representation of a portion of the Earth's crust based on in-situ geophysical, geological, and petrophysical data. The geological model can represent a whole reservoir or a part thereof. Dynamic well data and fluid data, including production periods and production rates, are incorporated into the geological model to generate a dynamic geological model (also called a transient model). This dynamic well data may belong to nearby offset wells or analogue wells. The output of the transient model includes pressure responses (reservoir pressures over time). An offset well refers to a well drilled in close proximity to an existing well. An analogue well refers to a well that has geological and operational characteristics similar to those of another well. The analogue wells are used as references or benchmarks for new drilling projects to predict performance, assess risks, and improve decision-making processes.

[0031] The geological data and geophysical data are acquired from a field seismic survey. The seismic field data can be analyzed and interpreted to derive reservoir structures, rock types, and reservoir features (fractures, faults, unconformity, etc.) of a reservoir. A contour map is generated based on the shape of the reservoir and depth scales. A rock type is determined by using the contour map and seismic interpretation. The reservoir structures, rock types, and reservoir features are incorporated into the geological model.

[0032] The petrophysical data includes reservoir properties (e.g., permeability, porosity, saturations, net oil-bearing thickness, and core data) that originate from petrophysical logs. Petrophysical logs are built during the drilling phase of the well. Logging tools are run in holes and wellbores to collect raw data about rock and fluid, which is later processed and analyzed to estimate detailed reservoir properties, such as permeability, porosity, saturations, thickness, etc. Petrophysical logs have the resolution of collecting localized features in the well or in the vicinity of the well. Petrophysical logs are the primary sources of data that have detailed descriptions of the rock, fluid, and well. The petrophysical data is input into a computer-aided geological model.

[0033] The geological data and geophysical data depict a general picture of the reservoir. Petrophysical data is directed to the wellbore and fluid revelation. The dynamic data identifies the actual reservoir fluids, reservoir pressure, and reservoir features, including production and pressure transient data. During the production period, fluids flow to the surface of the operating well (e.g., an offset well or an analogue well), the actual reservoir fluids are recovered, and production rate and pressure response are measured and tested. The pressure transient test can be performed when fluids flow or the well is shut in. The well's production rates and pressure responses are recorded mostly downhole by deploying downhole gauges. These flowing and shut-in pressure responses can indicate deep reservoir information. The production and pressure transient data are incorporated into the geological model, thereby transforming the geological model into a dynamic geological model (also called a transient model or simulation model). The dynamic data can be acquired only when the well is in operation.

[0034] The PVT data refers to reservoir fluid properties. A PVT analysis can determine fluid behaviors and properties of oil, water, and gas samples from a reference well. Fluid samples for PVT analyses are collected from the well during the drilling or production phase of the well. The PVT data can also define the phase behavior of reservoir fluids. Formation volume factor, viscosity, gas gravity, gas oil ratio, and water salinity data are utilized in the transient model, based on the number of phases (e.g., two or three phases) in the reservoir.

[0035] Reservoir initial conditions refer to the conditions when the well was drilled or before the well was subject to any production or injection. The pressure and temperature data collected at that time is called the initial pressure and temperature of the reservoir. These initial conditions are utilized to build a hydro-dynamically balanced version of a dynamic geological model right before the production or injection takes place.

[0036] In some implementations, if there is more than one fluid in the reservoir, the fluid-contact data, such as fluid phases (e.g., gas to oil and oil to water) and depth at which fluid phases change, is required. The depth at which fluid phases change is called a fluid-contact depth. The fluid-contact depths define the depths of interfaces between two adjacent phases (e.g., gas-oil, oil-water, gas-water interfaces) in the reservoir. These depths are references for pressure calculations in the transient models.

[0037] The reference point is the depth where all gauges are set downhole to measure the pressures with time. The pressure at the reference point (gauge depth of the pressure measurements) is required to initialize and simulate the production data in the transient model. The simulated production data can be utilized to further calibrate a large reservoir model.

[0038] The viability of a reservoir depends upon three parameters: (i) porosity of the reservoir rock, which defines the pore space available for in-situ reservoir fluids including hydrocarbons; (ii) permeability, which defines the easiness of extracting any hydrocarbons in place; and (iii) hydrocarbon saturation, which defines how much of the pore space is occupied by hydrocarbons. The hydrocarbon saturation is controlled by capillary pressure. Capillary pressure (Pc) is used to define a transition zone in a two-phase or three-phase system. The capillary pressure data originates from either petrophysical logs or laboratory analyses. The saturation function indicates how saturation changes at a particular location of the reservoir.

[0039] Relative permeability is used to enforce a preferential level flow capacity due to the presence of multiple fluids at a given location in the reservoir. Relative permeability is dependent upon pore geometry, wettability, fluid distribution, and fluid saturation history. In a single-phase system, such as a dry gas or an under-saturated oil reservoir, the effective permeability of the flow of the mobile fluid through the reservoir varies a little during production because the fluid saturation barely changes. By contrast, when more than one phase is mobile, the effective permeability to each mobile phase changes as the saturation of the fluid changes in the reservoir. In multiphase flow through porous media, the relative permeability of a phase is a dimensionless measure of the effective permeability of that phase. The relative permeability of a phase is the ratio of the effective permeability of that phase to the absolute permeability. Relative permeability is required for the calculation of permeability in each phase.

[0040] The proposed well trajectory is the well path inside a reservoir along which the planned well is supposed to follow the drilled path. In some examples, the well trajectory can be a straight, vertical line. In some examples, the well trajectory can be curved to maximize contact with reservoir layers.

[0041] In some implementations, enhanced oil recovery techniques are employed to maintain the reservoir pressure and improve the oil recovery from an existing reservoir. Different fluids are injected into a reservoir. The oil recovery techniques can provide pressure support to a producer (production well), displace the hydrocarbons of the producer, and sweep them towards the producer. The appropriate spacing between the producer well (e.g., a multilateral well) and an injector well can facilitate better and long-term recovery of hydrocarbons. To determine the appropriate spacing, a drilled or planned injection well trajectory is subject to sensitivity analysis and assessment of the injection well pressure responses.Subprocess 300B

[0042] The subprocess 300B illustrates an example process of determining the geometrical parameters of a multilateral well.

[0043] At 302, the reservoir data and well data are input to the geological model to transform the geological model into a transient model. FIG. 4 illustrates the transformation of a geological model 402 to a transient model 404, according to some implementations. As shown in FIG. 4, the geological model 402 is reliable and efficient because it incorporates realistic reservoir and well data from the hydrocarbon field. The geological model 402 is a building block of transient model 404. If the transient data (e.g., pressure transient data) is available in an offset or analogue well, then it is utilized to condition the geological model around the proposed wellbore and the region away from the wellbore. The reservoir data utilized to build the geological model primarily originates from the geology, geophysics, rock, fluid properties, petrophysical, and measurements during field operations.

[0044] The output of the transient model 404 shown in FIG. 4 can include the simulated pressure responses under well-flowing and shut-in conditions. The pressure changes in a time series as simulated pressure responses are utilized to estimate the well-flowing pressure and the average reservoir pressure. These values are utilized in calculating the productivity index as a measure of the quantitative performance of the well.

[0045] When the transient data or dynamic data of an offset or analogue well is available, to comply with the transient data or dynamic data, reservoir properties of the geological model are altered so that the altered model behaves as if an actual reservoir. Due to heterogeneity, reservoir properties in different portions of a reservoir may be different. A well can achieve a target production rate at a proposed location after the geological model is compliant with the measured transient data. The geological model is built using static data such as petrophysical logs and core data of a reservoir, as well as petrophysical logs and core data from other offset reservoirs nearby. The geological model can only predict reservoir properties near the wellbore based on the petrophysical logs and core data. However, reservoir properties may change away from the wellbore, particularly in a heterogeneous reservoir. The transient data, when available, may propagate deep into a reservoir up to kilometers, and the actual reservoir conditions can be sensed from far-away locations. The available transient data can be incorporated into the geological model, and reservoir properties are adjusted in compliance with the transient data. After incorporating the transient data into the geological model, the resulting geological model is considered a dynamic or transient model.

[0046] In some examples, a multi-layer transient model (e.g., a sixteen-layer transient model) is built based on a geological model. FIG. 5 illustrates an example multilateral well 502 placed on a multi-layer transient model 504 representing a reservoir. The geometrical parameters of the multilateral well 502 are optimized, and the controller 1500 can place / design the multilateral well 502 to achieve the maximum productivity / injectivity index.

[0047] At 304, after building the transient model from the geological model, the controller 1500 performs Quality assurance and quality control (QAQC) of the transient model with reference to input well and reservoir data or properties. During QAQC operations, practitioners can check if all the input well and reservoir data as shown in FIG. 4 are incorporated into the transient model correctly, and if the interpolation correlations are working as expected. Practitioners can check if all the geological features (barriers, faults, fractures, tight layers, etc.) that are derived from seismic and geology data analysis are incorporated correctly. Practitioners can check if reservoir properties (permeability, porosity, fluids saturation, saturation functions, relative permeability, fluids contacts, reservoir initial conditions) from the petrophysical log data (corrected based on core data if available), PVT data based on the collected samples and well data (perforations, geometry, production rates, etc.) are correct. In some implementations, there can be multiple wells in a geological model. Practitioners can check if the well completion and production data agree with the input well and reservoir properties and if they are defined correctly. QAQC can be performed based on the input data from each well in the geological model having a similar behavior and agreeing with the input well and reservoir data at respective well locations. QAQC of the transient model is performed with reference to input well and reservoir properties, to ensure that the input data is accurate and consistent with the well and reservoir configuration.

[0048] QAQC is performed to check that the input data, for example, well geometry, PVT, and production / injection, are added in order and that the measurement units are consistent and correct. For example, a depth unit in a well geometry is mistakenly selected in “meters” instead of “feet” when inputting the well data. As such, the well is thus placed at a distance away from the target reservoir. Upon completion of QAQC, such incoherence of the input data can be identified and rectified.

[0049] At 306, the controller 1500 checks if the transient model is acceptable after performing the QAQC and the well and reservoir data in the transient model agree with the input data, the controller 1500 performs 310. If the transient model is unacceptable, the controller 1500 performs 308 to adjust or correct the well and reservoir properties in the transient model. Otherwise, errors in the well and reservoir properties may lead to misleading results and interpretations.

[0050] In some implementations, if the actual recorded transient data, whenever available in offset or analogue wells, and the transient model pressure response are within a + / −5% difference, the transient model is considered acceptable. As an example, the reservoir properties are adjusted until the difference between the actual recorded pressure and the transient model pressure response is within + / −5%. The transient model pressure response is compared with the actual recorded transient data to demonstrate how the transient model is different from the original geological model. The actual (in-situ) reservoir properties are different from those of reservoir properties in the geological model because the reservoir is heterogeneous. By complying with the transient data, whenever available in offset or analogue wells, reservoir properties in the geological model are altered and corrected accordingly. After correcting the reservoir properties, the transient model pressure response matches with the actual transient data.

[0051] At 308, if the transient model is inconsistent with the input well and reservoir data, the controller 1500 adjusts the reservoir and well properties in the transient model according to the actual input well and reservoir data. After adjusting the well and reservoir properties in the geological model, the controller 1500 performs QAQC 304 again. Operations 306, 308, and 304 are iteratively performed until an acceptable transient model is built.

[0052] At 310, upon building the acceptable transient model, the controller 1500 runs a simulation to obtain a well location for drilling the multilateral well. The controller 1500 places a multilateral well along a proposed well trajectory and at the proposed location in the transient model utilizing a reservoir simulator. The controller 1500 runs a simulation by using a target production rate (e.g., a target production rate of 1,000 stock tank barrels per day (STB / D)) as a constraint. The controller 1500 can obtain a pressure response at the proposed location.

[0053] At 312, the controller 1500 evaluates the simulation result to determine whether the well can continuously produce hydrocarbon at the targeted production rate. If the simulation result suggests that the proposed multilateral well location can achieve the target production rate, the controller 1500 performs 316. Persons skilled in the art are able to determine if the well is capable of producing at the target production rate by examining the transient model or a simulated pressure response generated as an output of the transient model. The simulated pressure at any point in time is required not to fall below a predetermined pressure level based on fluid properties or other operational constraints. If the simulation result suggests that the proposed multilateral well location cannot achieve the target production rate, the controller 1500 performs 314 to adjust or move the well location.

[0054] At 314, if the proposed multilateral well location cannot achieve the target production rate, the controller 1500 adjusts or moves the well location in the transient model from the previously proposed location. The controller 1500 places the multilateral well at a new location, and runs a simulation 310 again to evaluate the new well location. The controller 1500 re-runs the simulation on the transient model by using the target production rate as a constraint to generate a pressure response (i.e., a simulated pressure over time) from the transient model for the new well location. Persons skilled in the art are able to determine if the well is capable of producing at the target production rate by examining the model or a simulated pressure response generated as an output of the transient model. The simulated pressure at any point in time is required not to fall below a predetermined pressure level based on reservoir properties, fluid properties or other operational constraints. If the new well location can achieve the production rate, the controller 1500 moves to 316; otherwise the controller 1500 iteratively adjusts the well location in the transient model until the target production rate can be satisfied (e.g., the production rate is equivalent to or within a predetermined range at or near the target production rate). Operations 310, 312, and 314 are iteratively performed until a final location meeting the target production rate is identified.

[0055] At 316, after determining the well location, the controller 1500 provides multiple lateral spacing options between the lateral sections (e.g., dual-lateral sections or tri-lateral sections) based on the transient model, offset wells nearby, and well configurations (e.g., dual-lateral sections, tri-lateral sections, or multiple lateral sections).

[0056] At 318, the controller 1500 runs simulation scenarios on the transient model for the multiple lateral spacing options and configurations, respectively. Each simulation scenario uses a target production rate as a constraint, and has a multilateral well placed at the final location determined at 310, 312, and 314. Each simulation scenario corresponds to a different lateral spacing and / or configuration. The controller 1500 adds a build-up period at the end of each simulation scenario for calculating PI according to Equation (1).PI=qpr-pwf(1)

[0057] Where q is production rate (e.g., barrels of oil per day), pr is reservoir pressure, and pwf is bottom-hole flowing pressure.

[0058] The build-up period refers to the duration during which the well is shut in following a certain duration of production. After shutting in the well to build up pressure, the reservoir pressure tends to reach its original or initial condition. The time required for any reservoir to reach its initial condition depends on its characteristics; for example, a good-quality reservoir (e.g., a homogeneous reservoir) reaches its original condition faster compared to a poor-quality reservoir (e.g., a heterogeneous reservoir). The change in reservoir pressure due to shutting in the well and production rates can be used to calculate the PI.

[0059] In some examples, the build-up period is long enough to achieve the late radial-flow regime on a log-log plot. Persons skilled in the art are able to determine if the build-up period is long enough. Interference between the lateral sections may mask the log-log plot data, which may impact PI calculation.

[0060] At 320, the controller 1500 calculates the PI for each simulation scenario by using the drawdown pressure response and build-up pressure response. Prior to calculating the PI, the controller 1500 generates a log-log plot from the build-up pressure response to ensure that the well has achieved the late radial-flow regime. The late radial-flow regime is a phase in the pressure transient analysis of a well where the pressure response truly represents the reservoir behaviors and the in-situ properties thereof.

[0061] In a homogenous reservoir, the relationship between PI and the lateral spacing can be linear after overcoming the interference between the lateral sections. By contrast, in a heterogeneous reservoir, the PI response can be nonlinear. Well configuration (the number of lateral sections) can also impact the PI values.

[0062] The build-up pressure response refers to a rise in well pressure as a function of time observed after a well is shut in or after the production rate is reduced. The build-up pressure response refers to a changing pressure at a downhole location in the well over time when the well is shut in after a certain period of production. During the build-up period, the well is subject to a zero-production rate. The pressure drawdown is a difference between the original reservoir pressure and the current flowing wellbore pressure. This pressure difference or drawdown at a given time drives fluids out of the reservoir into the wellbore. The drawdown period is the duration of the well when it is in production, and the build-up period is the duration when the well is shut in following the production.

[0063] At 322, the controller 1500 selects a lateral spacing from the multiple lateral spacing options and well configuration based on PI values. In some examples, a dual-lateral well may perform better in terms of PI than a tri-lateral well.

[0064] At 324, After selecting the lateral spacing and well configuration, the controller 1500 runs simulation scenarios for multiple well length options. An optimal well length can enable better reservoir contacts. The controller 1500 runs simulation scenarios by adding a build-up period at the end of the production period. The build-up period is long enough to achieve the late radial-flow regime on the log-log plot (a plot of pressure change versus time). Interference between the lateral sections may mask the log-log plot of pressure response, which may impact the calculation of PI.

[0065] At 326, the controller 1500 calculates and compares the PI for each well length option using the drawdown and build-up pressure responses. Before calculating the PI, the controller 1500 generates the log-log plot from the build-up pressure response. Persons skilled in the art understand that the well is subject to the late radial-flow regime. The controller 1500 selects the optimal well length corresponding to the largest PI value, from the multiple well length options, for the multilateral well. The selected well length can be practically achievable in the technological and geological environment. The multilateral well with the selected well length does not impact the offset wells.

[0066] At 328, the controller 1500 generates a virtual multilateral well at the selected well location, lateral spacing, and configuration to obtain the maximum hydrocarbon recovery.Subprocess 300C

[0067] In some implementations, to maintain the reservoir pressure and improve the oil recovery, a reservoir can employ enhanced oil recovery techniques by injecting different fluids into the reservoir. The fluid injection provides pressure support to a producer (e.g., a multilateral well that produces hydrocarbons), displaces hydrocarbons, and sweeps the hydrocarbons toward the producer.

[0068] At 330, the controller 1500 places a virtual injection well at a certain distance from the producer well (e.g., a multilateral well) and obtains an injection pressure response and water cut at the producer well. The controller 1500 runs a sensitivity analysis for multiple spacing options between the injector well (an injection well that injects fluids into the reservoir) and the producer well by moving the injector well close to or far away from the producer well and records injection pressure responses and water cut responses at the producer well.

[0069] At 332, the controller 1500 compares the pressure response and water cut responses for multiple injector-to-producer spacing options. An injector well close to the producer well can have an injection pressure response fast. A closer injector well may trigger an early water breakthrough and a high water cut at the producer well as well.

[0070] At 334, the controller 1500 selects a spacing from the multiple spacing options between the producer well and the injector well based on pressure response and water cut responses.

[0071] The example process 300 provides computer-aided techniques for geometrically optimizing a multilateral well. Multiple geometrical optimizations (selecting geometrical parameters) are performed around each main wellbore to place the lateral sections and to determine the number of lateral sections. The geometrical optimizations can minimize the competition among the lateral sections and maximize the drainage area, thereby increasing the well productivity index. As to a permeable reservoir, interference / competition among the lateral sections occurs fast. As to a tight or low-quality reservoir, the occurrence of interference / competition is delayed. The well productivity index is calculated for each simulation scenario, and a productivity index graph is generated as a measure of performance of the well quantitatively against each geometrical parameter based on the transient model. Graphical presentation of the productivity index can facilitate the determination of the optimal multilateral well design. Additional sensitivity analysis is performed to show the impact of reservoir heterogeneity, lateral-section lengths, lateral spacing, number of lateral sections, and the impact of offset producers / injectors.

[0072] The example process 300 can build a transient model using a geological model. The transient model can be built for any type of reservoir (homogeneous or heterogeneous) based on the reservoir description and properties. After building the transient model, dynamic production data (e.g., pressure response, production rate), whenever available in offset or analogue wells, is incorporated into the model, and simulation is run directly on this transient model. PI is calculated for each simulation scenario based on simulation responses (e.g., pressure responses), which are generated for different well locations, multilateral spacings, configurations, and well lengths. Before calculating the PI from drawdown pressure response and build-up pressure response, the pressure derivative for the simulated pressure is made on the log-log plot to confirm that the interference between the lateral is not impacting the build-up pressure response or that the build-up period has passed the interference region and achieved the late radial flow regime. After achieving satisfactory build-up pressure response, the controller 1500 compares PI values in terms of geometrical parameters of a multilateral well, such as lateral spacing, configuration (the number of lateral sections), and well length. As to a depleted reservoir, the spacing between offset injectors and the multilateral well can be optimized or determined by estimating injection well responses and water cut responses.Identify Optimal Location

[0073] Prior to the optimization of the geometrical parameters of a multilateral well, the controller 1500 selects a well location that meets a target production rate. FIG. 6 illustrates multiple locations 602, 604, 606, 608, and 610 for determining an optimized location to drill a multilateral well, according to some implementations. The controller 1500 can place a virtual multilateral well at the proposed location 602 and multiple locations 604, 606, 608, and 610 in the vicinity of the proposed location 602 and simulate production rates, respectively. The controller 1500 can select the optimal location from the multiple locations 602, 604, 606, 608, and 610.

[0074] FIG. 7 illustrates pressure response and production rate when drilling a multilateral well at proposed location 602, according to some implementations. As shown in FIG. 7, the multilateral well at location 602 produces more water than oil. Thus, location 602 is not an optimal location for drilling the multilateral well. The multilateral well is placed at locations 602, 604, 606, 608, and 610 to obtain production rate and pressure response, respectively. Location 606 is selected as the optimal location where the multilateral well can meet a production target.

[0075] FIG. 8 illustrates pressure response and production rate when drilling a multilateral well at location 606, according to some implementations. The transient response, including pressure response and production rate, is output by a transient model. As shown in FIG. 8, the multilateral well flows at specified oil and water production rates for a certain time period that is followed by a shut-in period. FIG. 8 also shows simulated flowing and shut-in pressures. These pressures are utilized in computing the productivity index of the multilateral well.Identify Optimal Lateral Spacing and Configuration

[0076] After selecting the well location, the controller 1500 selects an optimal spacing between the lateral sections to manage competition in the drainage area. In the drainage area, each lateral section tries to expand its drainage territory. All the lateral sections may compete for fluid extraction from the same zone. Competition in this drainage area can impact the PI. The objective of the optimal multilateral well is to acquire the maximum reservoir contact and PI. A multilateral well can perform better when draining from a non-competing drainage area. The selection of an optimal spacing between the lateral sections and an appropriate configuration with the number of lateral sections can optimize the drainage area. Simulation scenarios are performed for different configurations (the number of lateral sections) and spacing options.

[0077] FIG. 9 illustrates different lateral configurations of lateral sections in a heterogeneous reservoir, according to some implementations. As shown in FIG. 9, the multilateral well includes two lateral sections 902 or three lateral sections 904. FIG. 10 illustrates a PI graph with respect to lateral spacings for different lateral configurations, according to some implementations.

[0078] A lateral configuration is associated with heterogeneity due to reservoir geology. In some implementations, compared to a tri-lateral well, a dual-lateral well may achieve a better PI if the reservoir quality is degrading on one side of the proposed well location. Compared to a tri-lateral well, the dual-lateral well can save resources, including manpower and expenses.

[0079] As shown in curve 1002 representing a tri-lateral well of FIG. 10, PI increases by about 70% with respect to a lateral spacing increasing from 100 meters to 400 meters. When the lateral spacing increases from 400 meters to 600 meters, PI only increases by 10%. FIG. 10 suggests that any increase in lateral spacing further than 400 meters only adds marginal PI while occupying more reservoir area laterally. Lateral coverage of the reservoir area while adding marginal PI may prevent drilling more wells in the field, thereby suppressing reservoir recovery. FIG. 10 suggests that a lateral spacing of 400 meters is the optimal option. With this spacing of 400 meters, the lateral interference is minimal, and the competition in the drainage area is also minimized. The curve 1002 shows the lowest productivity index at 100 meters spacing due to pressure interference of lateral sections. Because all the lateral sections are trying to produce from the same drainage area, the well PI is impacted negatively. As the other two lateral sections L2 and L3 move away from L1, the pressure interference gets less. Less pressure interference can reduce the competition in the drainage area, thereby increasing the productivity index.

[0080] Referring to curve 1004 of FIG. 10, as to a dual lateral well with lateral sections L1 and L2, the PI value almost doubles when the lateral spacing changes from 100 meters to 600 meters, even though the PI value is less than that of the tri-lateral well. Referring to curve 1006 of FIG. 10, the dual lateral well with lateral sections L1 and L3 shows a poor response in PI, and the PI decreases as the lateral spacing increases. The curve 1006 suggests that the reservoir heterogeneity plays a dominant role as the reservoir quality degrades towards the lateral section L3. Any increase in lateral spacing of more than 400 meters between the lateral sections can impact PI. Curve 1006 shows that increasing the lateral spacing over 400 meters corresponds to a decrease in the PI, and suggests that the lateral spacing over 400 meters places the lateral section L3 in a lower-quality reservoir area. The curve 1004 of the dual lateral sections L1 and L2 suggests that an increase in the lateral spacing of more than 400 meters can bring an increase in PI, while the curve 1006 of the lateral sections L1 and L3 suggests an opposite trend.

[0081] The controller 1500 can identify well configuration (the number of lateral sections) and lateral spacing corresponding to the optimal PI. In the example of FIG. 10, the lateral spacing of 400 meters is optimal because a further increase of more than 400 meters in the lateral spacing provides a marginal increase in PI while covering more area of the reservoir. The coverage of more areas of the reservoir can result in fewer wells being drilled in the oil and gas field, thereby impacting the reservoir recovery.Identify Optimal Well Length

[0082] After identifying the optimal configuration and lateral spacing based on PI, the controller 1500 determines a well length (the length of each lateral section) to further maximize the PI. Well length plays a major role in well productivity while directly impacting drilling costs. The determined well length is required to be accountable to economics. As to a good-quality, homogeneous reservoir, an increase in a well length leads to a high PI. As to a highly heterogeneous reservoir, an increase in a well length may not increase the PI. If a reservoir quality degrades, an increase in a well length may reduce or not change the PI. A sensitivity analysis for the well length can be performed to identify the optimal well length. Reservoir quality is a factor to be considered when performing the sensitivity analysis for well length. In a good-quality, homogeneous reservoir, interference between lateral sections can be perceived faster compared to a lower-quality, heterogeneous reservoir. The interference between the lateral sections may cause competition, thereby reducing the PI of the well. Thus, in some examples, an increase in well length does not increase PI due to interference.

[0083] FIG. 11 illustrates a PI graph with respect to lateral lengths, according to some implementations. As shown in FIG. 11, sensitivity analyses are performed for different well lengths. The X-axis of FIG. 11 represents the total length of a well (the total length of lateral sections of a well). As an example, each lateral section has the same length. The PI graph suggests that a tri-lateral well with a 21,000 ft total length (i.e., 7,000 ft length for each lateral section) is the optimal option considering both PI and drilling costs. The dual-lateral well with a 20,000 ft total length (i.e., 10,000 ft length for each lateral section) corresponds to a similar PI (the PI corresponds to the tri-lateral well with a 21,000 ft total length). However, considering operational limitations and future maintenance, such a long well may not be feasible. Therefore, the optimal well length is 7,000 ft for each lateral section, and the tri-lateral well is the optimal geometrical configuration.Identify Injector to Producer Spacing

[0084] To maintain reservoir pressure and improve oil recovery from an existing reservoir, oil recovery techniques are used by injecting different fluids into the reservoir. The recovery techniques are intended to provide pressure support to a producer well, displace hydrocarbons, and sweep them toward the producer well. The spacing between an injector well and the producer well is associated with the pressure response on the producer well. The spacing between an injector well and the producer can be determined based on the pressure response.

[0085] The injection pressure response and the level of pressure support are incorporated to maximize the PI and achieve the maximum recovery target. Sensitivity analyses are performed considering variations of the injector to producer spacing and injection rate. FIG. 12 illustrates a pressure response graph with respect to injector-to-producer spacings (e.g., 250 meters, 500 meters, 750 meters, 1000 meters), according to some implementations. If the injector-to-producer spacing is 500 meters, the producer well (Well 3) can support the highest pressure due to the least pressure drawdown at the producer well. As shown in FIG. 12, pressure response for each spacing and production rate at the producer well (Well 3) are presented in FIG. 12. In some implementations, water production at the producer well is also considered while determining the spacing between the injector well and the producer well. The spacing between the injector well and the producer well is required to allow a tolerable amount of water cut at the producer well. Persons skilled in the art can determine the optimal spacing based on the degree of pressure support at the producer well, the water cut, and the time delay of the first episode of water production at the producer well. In the example of FIG. 12, the optimal spacing is 750 meters, which is a tradeoff between a loss of some pressure support at the expense of less water cut and delayed water production at the producer well.

[0086] FIG. 13 illustrates another example process of determining an optimized location and optimized geometrical parameters to drill a multilateral well in a reservoir, according to some implementations. Process 1300 is described as being performed by a computing device including one or more processors or a controller, such as controller 1500 of FIG. 15. The example process 1300 shown in FIG. 13 can be modified or reconfigured to include additional, fewer, or different steps (not shown in FIG. 13), which can be performed in the order shown or in a different order.

[0087] At 1302, the controller 1500 builds a multi-layer transient model representing the reservoir based on a geological model. For example, the transient model can include 16 layers. While describing the reservoir geology in the best possible way, persons skilled in the art would intend to minimize the number of layers in the geological model or the transient model to minimize a computational load.

[0088] At 1304, the controller 1500 determines a location at the reservoir for placing at least one multilateral well by executing multiple simulation scenarios at the multi-layer transient model. In each simulation scenario, the at least one multilateral well is placed at a different candidate location. In some implementations, multiple candidate locations are provided and the controller 1500 selects the optimal location from the multiple candidate locations. The multilateral well is predicted to produce hydrocarbon at a target or desired production rate if the multilateral well is placed at the optimal location.

[0089] At 1306, the controller 1500 determines a lateral spacing between lateral sections of the multilateral well and a number of lateral sections by executing the multiple simulation scenarios that produce hydrocarbons at a target production rate. In each simulation scenario, the multilateral well is placed at the optimal location determined at 1304 and the multilateral well is simulated with a different combination of candidate lateral spacing and the number of lateral sections. A PI is calculated as a quantitative measure of the well performance for each simulation scenario. In some implementations, multiple candidate lateral spacings are provided and the controller 1500 selects the optimal lateral spacing from the multiple lateral spacings. The selection is based on a balance between PI and drilling costs.

[0090] At 1308, the controller 1500 determines a well length for each lateral section by executing the multiple simulation scenarios that produce hydrocarbons at a target production rate. In each simulation scenario, the multilateral well is placed at the optimal location determined at 1304 and the multilateral well is simulated with a different candidate well length and the optimal candidate lateral spacing and the optimal number of lateral sections determined at 1306. A PI is calculated as a quantitative measure of the well performance for each simulation scenario. In some implementations, multiple candidate well lengths are provided and the controller 1500 selects the optimal well length from the multiple well lengths. The selection is based on a balance between PI and drilling costs.

[0091] At 1310, the controller 1500 determines a spacing between the multilateral well and an injection well based on a pressure response and a water cut response at the multilateral well. In some implementations, multiple candidate spacings are provided and the controller 1500 selects the optimal spacing from the multiple spacings. The selection is based on a pressure response and a water cut response at the multilateral well.

[0092] At 1312, the controller 1500 places the multilateral well having the optimal lateral spacing, the optimal number of lateral sections, the optimal well length, and the optimal spacing between the multilateral well and an injection well at the optimal location in a simulation scenario. In some embodiments, the multilateral well with the optimal lateral spacing, the optimal number of lateral sections, and the optimal well length at the optimal location of a simulation scenario is rendered using a display device. In some embodiments, a real-world multilateral well is drilled at the reservoir with the optimal lateral spacing, the optimal number of lateral sections, and the optimal well length at the optimal location as simulated in the simulation scenario.

[0093] FIG. 14 illustrates hydrocarbon production operations 1400 that include both one or more field operations 1410 and one or more computational operations 1412, which exchange information and control exploration for the production of hydrocarbons. In some implementations, outputs of techniques of the present disclosure can be performed before, during, or in combination with the hydrocarbon production operations 1400, specifically, for example, either as field operations 1410 or computational operations 1412, or both.

[0094] Examples of field operations 1410 include forming / drilling a wellbore, hydraulic fracturing, producing through the wellbore, and injecting fluids (such as water) through the wellbore, to name a few. In some implementations, methods of the present disclosure can trigger or control the field operations 1410. For example, the methods of the present disclosure can generate data from hardware / software including sensors and physical data gathering equipment (e.g., seismic sensors, well logging tools, flow meters, and temperature and pressure sensors). The methods of the present disclosure can include transmitting the data from the hardware / software to the field operations 1410 and responsively triggering the field operations 1410 including, for example, generating plans and signals that provide feedback to and control physical components of the field operations 1410. Alternatively or in addition, the field operations 1410 can trigger the methods of the present disclosure. For example, implementing physical components (including, for example, hardware, such as sensors) deployed in the field operations 1410 can generate plans and signals that can be provided as input or feedback (or both) to the methods of the present disclosure.

[0095] Examples of computational operations 1412 include one or more computer systems 1420 that include one or more processors and computer-readable media (e.g., non-transitory computer-readable media) operatively coupled to the one or more processors to execute computer operations to perform the methods of the present disclosure. The computational operations 1412 can be implemented using one or more databases 1418, which store data received from the field operations 1410 and / or generated internally within the computational operations 1412 (e.g., by implementing the methods of the present disclosure) or both. For example, the one or more computer systems 1420 process inputs from the field operations 1410 to assess conditions in the physical world, the outputs of which are stored in the databases 1418. For example, seismic sensors of the field operations 1410 can be used to perform a seismic survey to map subterranean features, such as facies and faults. In performing a seismic survey, seismic sources (e.g., seismic vibrators or explosions) generate seismic waves that propagate in the Earth, and seismic receivers (e.g., geophones) measure reflections generated as the seismic waves interact with boundaries between layers of a subsurface formation. The source and received signals are provided to the computational operations 1412 where they are stored in the databases 1418 and analyzed by the one or more computer systems 1420.

[0096] In some implementations, one or more outputs 1422 generated by the one or more computer systems 1420 can be provided as feedback / input to the field operations 1410 (either as direct input or stored in the databases 1418). The field operations 1410 can use the feedback / input to control physical components used to perform the field operations 1410 in the real world.

[0097] For example, the computational operations 1412 can process the seismic data to generate three-dimensional (3D) maps of the subsurface formation. The computational operations 1412 can use these 3D maps to provide plans for locating and drilling exploratory wells. In some operations, the exploratory wells are drilled using logging-while-drilling (LWD) techniques which incorporate logging tools into the drill string. LWD techniques can enable the computational operations 1412 to process new information about the formation and control the drilling to adjust to the observed conditions in real time.

[0098] The one or more computer systems 1420 can update the 3D maps of the subsurface formation as information from one exploration well is received, and the computational operations 1412 can adjust the location of the next exploration well based on the updated 3D maps. Similarly, the data received from production operations can be used by the computational operations 1412 to control components of the production operations. For example, production well and pipeline data can be analyzed to predict slugging in pipelines leading to a refinery, and the computational operations 1412 can control machine operated valves upstream of the refinery to reduce the likelihood of plant disruptions that run the risk of taking the plant offline.

[0099] In some implementations of the computational operations 1412, customized user interfaces can present intermediate or final results of the above-described processes to a user. Information can be presented in one or more textual, tabular, or graphical formats, such as through a dashboard. The information can be presented at one or more on-site locations (such as at an oil well or other facility), on the Internet (such as on a webpage), on a mobile application (or app), or at a central processing facility.

[0100] The presented information can include feedback, such as changes in parameters or processing inputs, that the user can select to improve a production environment, such as in the exploration, production, and / or testing of petrochemical processes or facilities. For example, the feedback can include parameters that, when selected by the user, can cause a change to, or an improvement in, drilling parameters (including drill bit speed and direction) or overall production of a gas or oil well. The feedback, when implemented by the user, can improve the speed and accuracy of calculations, streamline processes, improve models, and solve problems related to efficiency, performance, safety, reliability, costs, downtime, and the need for human interaction.

[0101] In some implementations, the feedback can be implemented in real-time, such as to provide an immediate or near-immediate change in operations or in a model. The term real-time (or similar terms as understood by one of ordinary skill in the art) means that an action and a response are temporally proximate such that an individual perceives the action and the response occurring substantially simultaneously. For example, the time difference for a response to display (or for an initiation of a display) of data following the individual's action to access the data can be less than 1 millisecond (ms), less than 1 second(s), or less than 5 s. While the requested data need not be displayed (or initiated for display) instantaneously, it is displayed (or initiated for display) without any intentional delay, taking into account processing limitations of a described computing system and time required to, for example, gather, accurately measure, analyze, process, store, or transmit the data.

[0102] Events can include readings or measurements captured by downhole equipment such as sensors, pumps, bottom hole assemblies, or other equipment. The readings or measurements can be analyzed at the surface, such as by using applications that can include modeling applications and machine learning. The analysis can be used to generate changes to settings of downhole equipment, such as drilling equipment. In some implementations, values of parameters or other variables that are determined can be used automatically (such as through using rules) to implement changes in oil or gas well exploration, production / drilling, or testing. For example, outputs of the present disclosure can be used as inputs to other equipment and / or systems at a facility. This can be especially useful for systems or various pieces of equipment that are located several meters or several miles apart, or are located in different countries or other jurisdictions.

[0103] FIG. 15 is a schematic illustration of an example controller 1500 (or control system) that enables an example system to detect water leaks / loss and recommend corrective repair actions, according to some implementations. For example, the controller 1500 may be operable according to the processes 300 and 1300 of FIGS. 3 and 13. The controller 1500 is intended to include various forms of digital computers, such as printed circuit boards (PCB), processors, digital circuitry, or otherwise parts of a system for supply chain alert management. Additionally the system can include portable storage media, such as, Universal Serial Bus (USB) flash drives. For example, the USB flash drives may store operating systems and other applications. The USB flash drives can include input / output components, such as a wireless transmitter or USB connector that may be inserted into a USB port of another computing device.

[0104] The controller 1500 includes a processor 1510, a memory 1520, a storage device 1530, and an input / output interface 1540 communicatively coupled with input / output devices 1560 (for example, displays, keyboards, measurement devices, sensors, valves, pumps). Each of the components 1510, 1520, 1530, and 1540 are interconnected using a system bus 1550. The processor 1510 is capable of processing instructions for execution within the controller 1500. The processor may be designed using any of a number of architectures. For example, the processor 1510 may be a CISC (Complex Instruction Set Computers) processor, a RISC (Reduced Instruction Set Computer) processor, or a MISC (Minimal Instruction Set Computer) processor.

[0105] In one implementation, the processor 1510 is a single-threaded processor. In another implementation, the processor 1510 is a multi-threaded processor. The processor 1510 is capable of processing instructions stored in the memory 1520 or on the storage device 1530 to display graphical information for a user interface on the input / output interface 1540.

[0106] The memory 1520 stores information within the controller 1500. In one implementation, the memory 1520 is a computer-readable medium. In one implementation, the memory 1520 is a volatile memory unit. In another implementation, the memory 1520 is a non-volatile memory unit.

[0107] The storage device 1530 is capable of providing mass storage for the controller 1500. In one implementation, the storage device 1530 is a computer-readable medium. In various different implementations, the storage device 1530 may be a floppy disk device, a hard disk device, an optical disk device, or a tape device.

[0108] The input / output interface 1540 provides input / output operations for the controller 1500. In one implementation, the input / output devices 1560 include a keyboard and / or pointing device. In another implementation, the input / output devices 1560 includes a display unit for displaying graphical user interfaces.

[0109] There can be any number of controllers 1500 associated with, or external to, a computer system containing controller 1500, with each controller 1500 communicating over a network. Further, the terms “client,”“user,” and other appropriate terminology can be used interchangeably, as appropriate, without departing from the scope of the present disclosure. Moreover, the present disclosure contemplates that many users can use one controller 1500, and one user can use multiple controllers 1500.EMBODIMENTS / EXAMPLES

[0110] According to some non-limiting embodiments or examples, provided is a computer-implemented method for placing at least one multilateral well in a reservoir, comprising: building a multi-layer transient model representing the reservoir based on a geological model; determining a location at the reservoir for placing the at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0111] According to some non-limiting embodiments or examples, provided is an apparatus comprising a non-transitory, computer readable, storage medium that stores instructions that, when executed by at least one processor, cause the at least one processor to perform operations comprising: building a multi-layer transient model representing a reservoir based on a geological model; determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0112] According to some non-limiting embodiments or examples, provided is a system, comprising: one or more memory modules; and one or more hardware processors communicably coupled to the one or more memory modules, the one or more hardware processors configured to execute instructions stored on the one or more memory modules to perform operations comprising: building a multi-layer transient model representing a reservoir based on a geological model; determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0113] Further non-limiting aspects or embodiments are set forth in the following numbered embodiments:

[0114] Embodiment 1: A computer-implemented method for placing at least one multilateral well in a reservoir, comprising: building a multi-layer transient model representing the reservoir based on a geological model; determining a location at the reservoir for placing the at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0115] Embodiment 2: The computer-implemented method of Embodiment 1, further comprising determining a spacing between the at least one multilateral well and an injection well based on a pressure response and a water cut response at the at least one multilateral well.

[0116] Embodiment 3: The computer-implemented method of Embodiment 2, further comprising: receiving multiple candidate spacings between the at least one multilateral well and the injection well; performing a sensitivity analysis for each candidate spacing to obtain an injection pressure response and a water cut response at the at least one multilateral well; and selecting the spacing from the multiple candidate spacings based on the injection pressure response and the water cut response.

[0117] Embodiment 4: The computer-implemented method of any one of Embodiments 1-3, building the multi-layer transient model further comprising: providing reservoir data including one or more of geological data, geophysical data, petrophysical data, pressure, volume and temperature (PVT) data, reservoir initial conditions, fluid-contact data, reference point, capillary pressure, relative permeability and well data including one or more of a proposed multilateral well trajectory, an injection well trajectory, pressure response data, production rates to the geological model; and performing Quality assurance and quality control (QAQC) of the multi-layer transient model with reference to the reservoir data and the well data.

[0118] Embodiment 5: The computer-implemented method of any one of Embodiments 1-4, determining the location further comprising: executing a first simulation scenario with the at least one multilateral well placed at an initial location; in response to the at least one multilateral well failing to satisfy the target production rate at the initial location, adjusting the initial location and iteratively executing a new first simulation scenario at adjusted locations until the at least one multilateral well satisfies the target production rate; and determining that the adjusted location is the location for placing the at least one multilateral well.

[0119] Embodiment 6: The computer-implemented method of any one of Embodiments 1-5, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising: receiving multiple candidate lateral spacings for the at least one multilateral well; performing a simulation scenario for each candidate lateral spacing; calculating the first PI for each candidate lateral spacing; and selecting the lateral spacing from the multiple candidate lateral spacings based on the first PI.

[0120] Embodiment 7: The computer-implemented method of Embodiment 6, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising: prior to calculating the first PI, generating a log-log plot to identify a late radial-flow regime.

[0121] Embodiment 8: The computer-implemented method of any one of Embodiments 1-7, determining the well length for each lateral section further comprising: receiving multiple candidate well lengths for the at least one multilateral well; performing a simulation scenario for each candidate well length; calculating the second PI for each candidate well length; and selecting the well length from the multiple candidate well lengths based on the second PI.

[0122] Embodiment 9: An apparatus comprising a non-transitory, computer readable, storage medium that stores instructions that, when executed by at least one processor, cause the at least one processor to perform operations comprising: building a multi-layer transient model representing a reservoir based on a geological model; determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0123] Embodiment 10: The apparatus of Embodiment 9, the operations further comprising determining a spacing between the at least one multilateral well and an injection well based on a pressure response and a water cut response at the at least one multilateral well.

[0124] Embodiment 11: The apparatus of Embodiment 10, the operations further comprising: receiving multiple candidate spacings between the at least one multilateral well and the injection well; performing a sensitivity analysis for each candidate spacing to obtain an injection pressure response and a water cut response at the at least one multilateral well; and selecting the spacing from the multiple candidate spacings based on the injection pressure response and the water cut response.

[0125] Embodiment 12: The apparatus of any one of Embodiments 9-11, building the multi-layer transient model further comprising: providing reservoir data including one or more of geological data, geophysical data, petrophysical data, pressure, volume and temperature (PVT) data, reservoir initial conditions, fluid-contact data, reference point, capillary pressure, relative permeability and well data including one or more of a proposed multilateral well trajectory, an injection well trajectory, pressure response data, production rates to the geological model; and performing Quality assurance and quality control (QAQC) of the multi-layer transient model with reference to the reservoir data and the well data.

[0126] Embodiment 13: The apparatus of any one of Embodiments 9-12, determining the location further comprising: executing a first simulation scenario with the at least one multilateral well placed at an initial location; in response to the at least one multilateral well failing to satisfy the target production rate at the initial location, adjusting the initial location and iteratively executing a new first simulation scenario at adjusted locations until the at least one multilateral well satisfies the target production rate; and determining that the adjusted location is the location for placing the at least one multilateral well.

[0127] Embodiment 14: The apparatus of any one of Embodiments 9-13, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising: receiving multiple candidate lateral spacings for the at least one multilateral well; performing a simulation scenario for each candidate lateral spacing; calculating the first PI for each candidate lateral spacing; and selecting the lateral spacing from the multiple candidate lateral spacings based on the first PI.

[0128] Embodiment 15: The apparatus of Embodiment 14, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising: prior to calculating the first PI, generating a log-log plot to identify a late radial-flow regime.

[0129] Embodiment 16: The apparatus of any one of Embodiments 9-15, determining the well length for each lateral section further comprising: receiving multiple candidate well lengths for the at least one multilateral well; performing a simulation scenario for each candidate well length; calculating the second PI for each candidate well length; and selecting the well length from the multiple candidate well lengths based on the second PI.

[0130] Embodiment 17: A system, comprising: one or more memory modules; and one or more hardware processors communicably coupled to the one or more memory modules, the one or more hardware processors configured to execute instructions stored on the one or more memory modules to perform operations comprising: building a multi-layer transient model representing a reservoir based on a geological model; determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0131] Embodiment 18: The system of Embodiment 17, the operations further comprising determining a spacing between the at least one multilateral well and an injection well based on a pressure response and a water cut response at the at least one multilateral well.

[0132] Embodiment 19: The system of Embodiment 18, the operations further comprising: receiving multiple candidate spacings between the at least one multilateral well and the injection well; performing a sensitivity analysis for each candidate spacing to obtain an injection pressure response and a water cut response at the at least one multilateral well; and selecting the spacing from the multiple candidate spacings based on the injection pressure response and the water cut response.

[0133] Embodiment 20: The system of any one of Embodiments 17-19, determining the location further comprising: executing a first simulation scenario with the at least one multilateral well placed at an initial location; in response to the at least one multilateral well failing to satisfy the target production rate at the initial location, adjusting the initial location and iteratively executing a new first simulation scenario at adjusted locations until the at least one multilateral well satisfies the target production rate; and determining that the adjusted location is the location for placing the at least one multilateral well.

[0134] Implementations of the subject matter and the functional operations described in this specification can be implemented in digital electronic circuitry, in tangibly embodied computer software or firmware, in computer hardware, including the structures disclosed in this specification and their structural equivalents, or in combinations of one or more of them. Software implementations of the described subject matter can be implemented as one or more computer programs. Each computer program can include one or more modules of computer program instructions encoded on a tangible, non-transitory, computer-readable computer-storage medium for execution by, or to control the operation of, data processing apparatus. Alternatively, or additionally, the program instructions can be encoded in / on an artificially generated propagated signal. The example, the signal can be a machine-generated electrical, optical, or electromagnetic signal that is generated to encode information for transmission to suitable receiver apparatus for execution by a data processing apparatus. The computer-storage medium can be a machine-readable storage device, a machine-readable storage substrate, a random or serial access memory device, or a combination of computer-storage mediums.

[0135] The terms “data processing apparatus,”“computer,” and “electronic computer device” (or equivalent as understood by one of ordinary skill in the art) refer to data processing hardware. For example, a data processing apparatus can encompass all kinds of apparatus, devices, and machines for processing data, including by way of example, a programmable processor, a computer, or multiple processors or computers. The apparatus can also include special purpose logic circuitry including, for example, a central processing unit (CPU), a field programmable gate array (FPGA), or an application specific integrated circuit (ASIC). In some implementations, the data processing apparatus or special purpose logic circuitry (or a combination of the data processing apparatus or special purpose logic circuitry) can be hardware- or software-based (or a combination of both hardware- and software-based). The apparatus can optionally include code that creates an execution environment for computer programs, for example, code that constitutes processor firmware, a protocol stack, a database management system, an operating system, or a combination of execution environments. The present disclosure contemplates the use of data processing apparatuses with or without conventional operating systems, for example, LINUX, UNIX, WINDOWS, MAC OS, ANDROID, or IOS.

[0136] A computer program, which can also be referred to or described as a program, software, a software application, a module, a software module, a script, or code, can be written in any form of programming language. Programming languages can include, for example, compiled languages, interpreted languages, declarative languages, or procedural languages. Programs can be deployed in any form, including as stand-alone programs, modules, components, subroutines, or units for use in a computing environment. A computer program can, but need not, correspond to a file in a file system. A program can be stored in a portion of a file that holds other programs or data, for example, one or more scripts stored in a markup language document, in a single file dedicated to the program in question, or in multiple coordinated files storing one or more modules, sub programs, or portions of code. A computer program can be deployed for execution on one computer or on multiple computers that are located, for example, at one site or distributed across multiple sites that are interconnected by a communication network. While portions of the programs illustrated in the various figures may be shown as individual modules that implement the various features and functionality through various objects, methods, or processes, the programs can instead include a number of sub-modules, third-party services, components, and libraries. Conversely, the features and functionality of various components can be combined into single components as appropriate. Thresholds used to make computational determinations can be statically, dynamically, or both statically and dynamically determined.

[0137] The methods, processes, or logic flows described in this specification can be performed by one or more programmable computers executing one or more computer programs to perform functions by operating on input data and generating output. The methods, processes, or logic flows can also be performed by, and apparatus can also be implemented as, special purpose logic circuitry, for example, a CPU, an FPGA, or an ASIC.

[0138] Computers suitable for the execution of a computer program can be based on one or more of general and special purpose microprocessors and other kinds of CPUs. The elements of a computer are a CPU for performing or executing instructions and one or more memory devices for storing instructions and data. Generally, a CPU can receive instructions and data from (and write data to) a memory. A computer can also include, or be operatively coupled to, one or more mass storage devices for storing data. In some implementations, a computer can receive data from, and transfer data to, the mass storage devices including, for example, magnetic, magneto optical disks, or optical disks. Moreover, a computer can be embedded in another device, for example, a mobile telephone, a personal digital assistant (PDA), a mobile audio or video player, a game console, a global positioning system (GPS) receiver, or a portable storage device such as a universal serial bus (USB) flash drive.

[0139] Computer readable media (transitory or non-transitory, as appropriate) suitable for storing computer program instructions and data can include all forms of permanent / non-permanent and volatile / non-volatile memory, media, and memory devices. Computer readable media can include, for example, semiconductor memory devices such as random access memory (RAM), read only memory (ROM), phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), and flash memory devices. Computer readable media can also include, for example, magnetic devices such as tape, cartridges, cassettes, and internal / removable disks. Computer readable media can also include magneto optical disks and optical memory devices and technologies including, for example, digital video disc (DVD), CD ROM, DVD+ / −R, DVD-RAM, DVD-ROM, HD-DVD, and BLURAY. The memory can store various objects or data, including caches, classes, frameworks, applications, modules, backup data, jobs, web pages, web page templates, data structures, database tables, repositories, and dynamic information. Types of objects and data stored in memory can include parameters, variables, algorithms, instructions, rules, constraints, and references. Additionally, the memory can include logs, policies, security or access data, and reporting files. The processor and the memory can be supplemented by, or incorporated in, special purpose logic circuitry.

[0140] Implementations of the subject matter described in the present disclosure can be implemented on a computer having a display device for providing interaction with a user, including displaying information to (and receiving input from) the user. Types of display devices can include, for example, a cathode ray tube (CRT), a liquid crystal display (LCD), a light-emitting diode (LED), and a plasma monitor. Display devices can include a keyboard and pointing devices including, for example, a mouse, a trackball, or a trackpad. User input can also be provided to the computer through the use of a touchscreen, such as a tablet computer surface with pressure sensitivity or a multi-touch screen using capacitive or electric sensing. Other kinds of devices can be used to provide for interaction with a user, including to receive user feedback including, for example, sensory feedback including visual feedback, auditory feedback, or tactile feedback. Input from the user can be received in the form of acoustic, speech, or tactile input. In addition, a computer can interact with a user by sending documents to, and receiving documents from, a device that is used by the user. For example, the computer can send web pages to a web browser on a user's client device in response to requests received from the web browser.

[0141] The term “graphical user interface,” or “GUI,” can be used in the singular or the plural to describe one or more graphical user interfaces and each of the displays of a particular graphical user interface. Therefore, a GUI can represent any graphical user interface, including, but not limited to, a web browser, a touch screen, or a command line interface (CLI) that processes information and efficiently presents the information results to the user. In general, a GUI can include a plurality of user interface (UI) elements, some or all associated with a web browser, such as interactive fields, pull-down lists, and buttons. These and other UI elements can be related to or represent the functions of the web browser.

[0142] Implementations of the subject matter described in this specification can be implemented in a computing system that includes a back-end component, for example, as a data server, or that includes a middleware component, for example, an application server. Moreover, the computing system can include a front-end component, for example, a client computer having one or both of a graphical user interface or a Web browser through which a user can interact with the computer. The components of the system can be interconnected by any form or medium of wireline or wireless digital data communication (or a combination of data communication) in a communication network. Examples of communication networks include a local area network (LAN), a radio access network (RAN), a metropolitan area network (MAN), a wide area network (WAN), Worldwide Interoperability for Microwave Access (WIMAX), a wireless local area network (WLAN) (for example, using 802.11 a / b / g / n or 802.20 or a combination of protocols), all or a portion of the Internet, or any other communication system or systems at one or more locations (or a combination of communication networks). The network can communicate with, for example, Internet Protocol (IP) packets, frame relay frames, asynchronous transfer mode (ATM) cells, voice, video, data, or a combination of communication types between network addresses.

[0143] The computing system can include clients and servers. A client and server can generally be remote from each other and can typically interact through a communication network. The relationship of client and server can arise by virtue of computer programs running on the respective computers and having a client-server relationship. Cluster file systems can be any file system type accessible from multiple servers for read and update. Locking or consistency tracking may not be necessary since the locking of exchange file system can be done at application layer. Furthermore, Unicode data files can be different from non-Unicode data files.

[0144] While this specification contains many specific implementation details, these should not be construed as limitations on the scope of what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this specification in the context of separate implementations can also be implemented, in combination, in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any suitable sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.

[0145] Various components may be described as performing a task or tasks, for convenience in the description. Such descriptions should be interpreted as including the phrase “configured to.” Reciting a component that is configured to perform one or more tasks is expressly intended not to invoke 35 USC § 112(f) interpretation for that component.

[0146] Particular implementations of the subject matter have been described. Other implementations, alterations, and permutations of the described implementations are within the scope of the following claims as will be apparent to those skilled in the art. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. In certain circumstances, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and performed as deemed appropriate.

[0147] Moreover, the separation or integration of various system modules and components in the previously described implementations should not be understood as requiring such separation or integration in all implementations, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.

[0148] Accordingly, the previously described example implementations do not define or constrain the present disclosure. Other changes, substitutions, and alterations are also possible without departing from the spirit and scope of the present disclosure.

[0149] Furthermore, any claimed implementation is considered to be applicable to at least a computer-implemented method; a non-transitory, computer-readable medium storing computer-readable instructions to perform the computer-implemented method; and a computer system comprising a computer memory interoperably coupled with a hardware processor configured to perform the computer-implemented method or the instructions stored on the non-transitory, computer-readable medium.

[0150] Particular embodiments of the subject matter have been described. Other embodiments are within the scope of the following claims. For example, the actions recited in the claims can be performed in a different order and still achieve desirable results. As one example, some processes depicted in the accompanying figures do not necessarily require the particular order shown, or sequential order, to achieve desirable results.

Examples

embodiments / examples

EMBODIMENTS / EXAMPLES

[0110]According to some non-limiting embodiments or examples, provided is a computer-implemented method for placing at least one multilateral well in a reservoir, comprising: building a multi-layer transient model representing the reservoir based on a geological model; determining a location at the reservoir for placing the at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; det...

TECHNICAL FIELD

[0001] This disclosure relates generally to hydrocarbon exploration, drilling, and production, and more particularly, drilling of multilateral wells in reservoirs.BACKGROUND

[0002] Multilateral wells can be used for the production of oil and gas from hydrocarbon reservoirs. Multilateral wells involve drilling multiple branches from a single main wellbore. A multilateral well includes a main wellbore and lateral sections. The main wellbore is a primary vertical or horizontal well from which multiple lateral branches extend. Lateral sections are additional branches or secondary wellbores that extend from the main wellbore to access different parts of a reservoir.BRIEF DESCRIPTION OF THE FIGURES

[0003] FIG. 1 illustrates a multilateral well, intersecting different subsurface reservoir layers for the production of oil, according to some implementations.

[0004] FIG. 2 illustrates an example process of commercial development of a hydrocarbon field, according to some implementations.

[0005] FIG. 3 illustrates an example process of determining an optimized location and optimized geometrical parameters to drill a multilateral well in a reservoir, according to some implementations.

[0006] FIG. 4 illustrates the transformation of a geological model to a transient model, according to some implementations.

[0007] FIG. 5 illustrates an example multilateral well placed on a multi-layer transient model 504 representing a reservoir.

[0008] FIG. 6 illustrates multiple locations for drilling a multilateral well, according to some implementations.

[0009] FIG. 7 illustrates pressure response and production rate when drilling a multilateral well at proposed location, according to some implementations.

[0010] FIG. 8 illustrates pressure response and production rate when drilling a multilateral well at location, according to some implementations.

[0011] FIG. 9 illustrates different lateral configurations of lateral sections in a heterogeneous reservoir, according to some implementations.

[0012] FIG. 10 illustrates a productivity index (PI) graph with respect to lateral spacings for different lateral configurations, according to some implementations.

[0013] FIG. 11 illustrates a PI graph with respect to lateral lengths, according to some implementations.

[0014] FIG. 12 illustrates a pressure response graph at producer well with respect to injector-to-producer spacings, according to some implementations.

[0015] FIG. 13 illustrates another example process of determining an optimized location and optimized geometrical parameters to drill a multilateral well in a reservoir, according to some implementations.

[0016] FIG. 14 illustrates hydrocarbon production operations that include both one or more field operations and one or more computational operations, which exchange information and control exploration for the production of hydrocarbons, according to some implementations.

[0017] FIG. 15 is a schematic illustration of an example controller (or control system) that enables an example system to detect water leaks / loss and recommend corrective repair actions, according to some implementations.DETAILED DESCRIPTION

[0018] This disclosure describes methods and systems for geometrical optimization of a multilateral well and placement of the multilateral well in a reservoir, using a transient model. Geometrical parameters of the multilateral well can include a lateral spacing between lateral sections of the multilateral well, a configuration (the number of lateral sections), a drilled length of each lateral section, and a spacing between a nearby injector (e.g., water / gas injection well) and the multilateral well. Geometrical optimization of the multilateral well refers to drilling the multilateral well (with optimal lateral spacing, configuration, and drilled length) at an optimal location of the reservoir to maximize productivity index (PI) and hydrocarbon drainage by the multilateral well.

[0019] The transient model represents a reservoir and is constructed based on reservoir data (e.g., geological data, geophysical data, petrophysical data, pressure, volume and temperature (PVT) data, reservoir initial conditions, fluid-contact data (e.g., gas-oil contact, oil-water contact), reference point, capillary pressure, relative permeability) and well data (e.g., a proposed multilateral well trajectory, an injection well trajectory, and target production rates). The transient model represents a reservoir in simulation scenarios that are iteratively performed to determine the location of a multilateral well, a configuration of the multilateral well, lateral spacing between lateral sections, the length of each lateral section, and a spacing between the multilateral well and an injection well. The productivity index (PI) is calculated to determine the optimal configuration of a multilateral well in terms of the number of lateral sections, lateral spacing, and lengths of lateral sections.

[0020] The placement of a multilateral well in a hydrocarbon reservoir can facilitate minimizing the nominal number of wells in a hydrocarbon field while maximizing the contact of the intersecting well with the hydrocarbon reservoir. The greater reservoir contact of the multilateral well with a subsurface reservoir boosts the recovery of hydrocarbons with a superior sweep efficiency, compared to a conventional single-lateral, vertical or horizontal well. Drilling multiple branches (multiple lateral sections) of a well into a reservoir from a main or mother wellbore offers potential benefits in terms of improving drainage and productivity. The mother wellbore conveys fluids to or from the surface of the multilateral well. The multiple lateral sections can promote optimal sweeping of hydrocarbon out of the reservoir to maximize the recovery of hydrocarbon.

[0021] FIG. 1 illustrates a multilateral well 100, intersecting different subsurface reservoir layers for the production of oil, according to some implementations. The multilateral well 100 includes two or more lateral sections L1, L2, L3 drilled from a common trunk or main bore 102. The lateral sections L1, L2, L3 can be horizontal, vertical, or deviated. The lateral sections L1, L2, L3 can be in the same planes, or in different planes of reservoir 110. The lateral sections L1, L2, L3 are connected to the surface of the multilateral well 100 via main bore 102. Kickoff point 104 is the location where the lateral section L2 gets separated from the main bore 102. Kickoff point 106 is the location where the lateral section L3 gets separated from the main bore 102. The black portions (e.g., included in dotted rectangle 108) of the lateral sections L1, L2, L3 represent the corresponding perforated or open-hole intervals that have intersected the reservoir 110. These perforated or open hole intervals receive the drained fluid from the intersected reservoir 110, and convey the drained fluid to the surface of the multilateral well 100 through production strings.

[0022] FIG. 2 illustrates an example process 200 of commercial development of a hydrocarbon field, according to some implementations. The example process 200 includes exploration of a hydrocarbon field 202, appraisal of the hydrocarbon field 204, hydrocarbon field development 206, oil production 208, and abandonment of the hydrocarbon field 210. The geometrical optimization of a multilateral well in this disclosure is included in the hydrocarbon field development 206.

[0023] The geometrical optimization of a multilateral well in this disclosure enables multiple local optimizations to be performed iteratively around a main wellbore to place lateral sections and determine the number of lateral sections required to meet a production target. The geometrical optimization can manage and optimize the competition among the lateral sections and maximize the drainage area, thereby increasing the well productivity index or injectivity index. With different geometrical parameter settings of a multilateral well, a well productivity index is calculated for each setting to assess the performance of the well quantitatively. A productivity index graph including all the well productivity indices for different settings is generated. Graphical presentation of the productivity indices can track, guide, and decide on the optimal geometrical parameters of a multilateral well.

[0024] In some implementations, the geometrical optimization of a multilateral well is performed using a transient model. The transient model provides a platform for hosting a reservoir with geological structures and reservoir properties. The transient model also hosts at least one multilateral well with well properties (such as well trajectories, lengths of lateral sections, lateral spacing, the number of lateral sections, a spacing between the multilateral well and an injection well) for calculating productivity indices. Additionally, reservoir heterogeneity and interference among the lateral sections can also impact the productivity of the multilateral well.

[0025] In some implementations, if the spacing between multilateral sections is too small, the drainage area of the multilateral sections may overlap, which can impact the well productivity negatively. If the spacing between the lateral sections is too large, the multilateral well may not be able to sweep the reservoir efficiently. The disclosed techniques in this disclosure strike a balance between the drainage area and the inherent interference among the lateral sections.

[0026] The disclosed techniques can enable persons skilled in the art to determine the optimal geometrical parameters of a multilateral well, such as the number of lateral sections, lateral spacing, and lengths of lateral sections. The optimal geometrical parameters can maximize a productivity index, so that the additional productivity outweighs the costs of investment in the multilateral well.

[0027] FIG. 3 illustrates an example process 300 of determining an optimized location and optimized geometrical parameters to drill a multilateral well in a reservoir, according to some implementations. Process 300 is described as being performed by a computing device including one or more processors or a controller, such as controller 1500 of FIG. 15. The example process 300 shown in FIG. 3 can be modified or reconfigured to include additional, fewer, or different steps (not shown in FIG. 3), which can be performed in the order shown or in a different order.

[0028] The example process 300 can be divided into three subprocesses 300A, 300B, and 300C. The subprocess 300A is directed to building a transient model. The subprocess 300B is directed to the preparation, execution, verification, analysis, and selection of the optimal or acceptable geometrical parameters of a multilateral well. The subprocess 300C is directed to determining injector-to-producer spacing (a distance between an injector well and the multilateral well).Subprocess 300A

[0029] The input of the transient model built in the subprocess 300A can include reservoir properties including reservoir geology and engineering properties of rocks and well properties at different locations including the respective trajectories, historical production rates, and reservoir pressures. The output of the transient model can include, for example, simulated pressure responses under well-flowing and shut-in conditions, etc.

[0030] In some implementations, the transient model is built based on a geological model. The geological model is a computerized representation of a portion of the Earth's crust based on in-situ geophysical, geological, and petrophysical data. The geological model can represent a whole reservoir or a part thereof. Dynamic well data and fluid data, including production periods and production rates, are incorporated into the geological model to generate a dynamic geological model (also called a transient model). This dynamic well data may belong to nearby offset wells or analogue wells. The output of the transient model includes pressure responses (reservoir pressures over time). An offset well refers to a well drilled in close proximity to an existing well. An analogue well refers to a well that has geological and operational characteristics similar to those of another well. The analogue wells are used as references or benchmarks for new drilling projects to predict performance, assess risks, and improve decision-making processes.

[0031] The geological data and geophysical data are acquired from a field seismic survey. The seismic field data can be analyzed and interpreted to derive reservoir structures, rock types, and reservoir features (fractures, faults, unconformity, etc.) of a reservoir. A contour map is generated based on the shape of the reservoir and depth scales. A rock type is determined by using the contour map and seismic interpretation. The reservoir structures, rock types, and reservoir features are incorporated into the geological model.

[0032] The petrophysical data includes reservoir properties (e.g., permeability, porosity, saturations, net oil-bearing thickness, and core data) that originate from petrophysical logs. Petrophysical logs are built during the drilling phase of the well. Logging tools are run in holes and wellbores to collect raw data about rock and fluid, which is later processed and analyzed to estimate detailed reservoir properties, such as permeability, porosity, saturations, thickness, etc. Petrophysical logs have the resolution of collecting localized features in the well or in the vicinity of the well. Petrophysical logs are the primary sources of data that have detailed descriptions of the rock, fluid, and well. The petrophysical data is input into a computer-aided geological model.

[0033] The geological data and geophysical data depict a general picture of the reservoir. Petrophysical data is directed to the wellbore and fluid revelation. The dynamic data identifies the actual reservoir fluids, reservoir pressure, and reservoir features, including production and pressure transient data. During the production period, fluids flow to the surface of the operating well (e.g., an offset well or an analogue well), the actual reservoir fluids are recovered, and production rate and pressure response are measured and tested. The pressure transient test can be performed when fluids flow or the well is shut in. The well's production rates and pressure responses are recorded mostly downhole by deploying downhole gauges. These flowing and shut-in pressure responses can indicate deep reservoir information. The production and pressure transient data are incorporated into the geological model, thereby transforming the geological model into a dynamic geological model (also called a transient model or simulation model). The dynamic data can be acquired only when the well is in operation.

[0034] The PVT data refers to reservoir fluid properties. A PVT analysis can determine fluid behaviors and properties of oil, water, and gas samples from a reference well. Fluid samples for PVT analyses are collected from the well during the drilling or production phase of the well. The PVT data can also define the phase behavior of reservoir fluids. Formation volume factor, viscosity, gas gravity, gas oil ratio, and water salinity data are utilized in the transient model, based on the number of phases (e.g., two or three phases) in the reservoir.

[0035] Reservoir initial conditions refer to the conditions when the well was drilled or before the well was subject to any production or injection. The pressure and temperature data collected at that time is called the initial pressure and temperature of the reservoir. These initial conditions are utilized to build a hydro-dynamically balanced version of a dynamic geological model right before the production or injection takes place.

[0036] In some implementations, if there is more than one fluid in the reservoir, the fluid-contact data, such as fluid phases (e.g., gas to oil and oil to water) and depth at which fluid phases change, is required. The depth at which fluid phases change is called a fluid-contact depth. The fluid-contact depths define the depths of interfaces between two adjacent phases (e.g., gas-oil, oil-water, gas-water interfaces) in the reservoir. These depths are references for pressure calculations in the transient models.

[0037] The reference point is the depth where all gauges are set downhole to measure the pressures with time. The pressure at the reference point (gauge depth of the pressure measurements) is required to initialize and simulate the production data in the transient model. The simulated production data can be utilized to further calibrate a large reservoir model.

[0038] The viability of a reservoir depends upon three parameters: (i) porosity of the reservoir rock, which defines the pore space available for in-situ reservoir fluids including hydrocarbons; (ii) permeability, which defines the easiness of extracting any hydrocarbons in place; and (iii) hydrocarbon saturation, which defines how much of the pore space is occupied by hydrocarbons. The hydrocarbon saturation is controlled by capillary pressure. Capillary pressure (Pc) is used to define a transition zone in a two-phase or three-phase system. The capillary pressure data originates from either petrophysical logs or laboratory analyses. The saturation function indicates how saturation changes at a particular location of the reservoir.

[0039] Relative permeability is used to enforce a preferential level flow capacity due to the presence of multiple fluids at a given location in the reservoir. Relative permeability is dependent upon pore geometry, wettability, fluid distribution, and fluid saturation history. In a single-phase system, such as a dry gas or an under-saturated oil reservoir, the effective permeability of the flow of the mobile fluid through the reservoir varies a little during production because the fluid saturation barely changes. By contrast, when more than one phase is mobile, the effective permeability to each mobile phase changes as the saturation of the fluid changes in the reservoir. In multiphase flow through porous media, the relative permeability of a phase is a dimensionless measure of the effective permeability of that phase. The relative permeability of a phase is the ratio of the effective permeability of that phase to the absolute permeability. Relative permeability is required for the calculation of permeability in each phase.

[0040] The proposed well trajectory is the well path inside a reservoir along which the planned well is supposed to follow the drilled path. In some examples, the well trajectory can be a straight, vertical line. In some examples, the well trajectory can be curved to maximize contact with reservoir layers.

[0041] In some implementations, enhanced oil recovery techniques are employed to maintain the reservoir pressure and improve the oil recovery from an existing reservoir. Different fluids are injected into a reservoir. The oil recovery techniques can provide pressure support to a producer (production well), displace the hydrocarbons of the producer, and sweep them towards the producer. The appropriate spacing between the producer well (e.g., a multilateral well) and an injector well can facilitate better and long-term recovery of hydrocarbons. To determine the appropriate spacing, a drilled or planned injection well trajectory is subject to sensitivity analysis and assessment of the injection well pressure responses.Subprocess 300B

[0042] The subprocess 300B illustrates an example process of determining the geometrical parameters of a multilateral well.

[0043] At 302, the reservoir data and well data are input to the geological model to transform the geological model into a transient model. FIG. 4 illustrates the transformation of a geological model 402 to a transient model 404, according to some implementations. As shown in FIG. 4, the geological model 402 is reliable and efficient because it incorporates realistic reservoir and well data from the hydrocarbon field. The geological model 402 is a building block of transient model 404. If the transient data (e.g., pressure transient data) is available in an offset or analogue well, then it is utilized to condition the geological model around the proposed wellbore and the region away from the wellbore. The reservoir data utilized to build the geological model primarily originates from the geology, geophysics, rock, fluid properties, petrophysical, and measurements during field operations.

[0044] The output of the transient model 404 shown in FIG. 4 can include the simulated pressure responses under well-flowing and shut-in conditions. The pressure changes in a time series as simulated pressure responses are utilized to estimate the well-flowing pressure and the average reservoir pressure. These values are utilized in calculating the productivity index as a measure of the quantitative performance of the well.

[0045] When the transient data or dynamic data of an offset or analogue well is available, to comply with the transient data or dynamic data, reservoir properties of the geological model are altered so that the altered model behaves as if an actual reservoir. Due to heterogeneity, reservoir properties in different portions of a reservoir may be different. A well can achieve a target production rate at a proposed location after the geological model is compliant with the measured transient data. The geological model is built using static data such as petrophysical logs and core data of a reservoir, as well as petrophysical logs and core data from other offset reservoirs nearby. The geological model can only predict reservoir properties near the wellbore based on the petrophysical logs and core data. However, reservoir properties may change away from the wellbore, particularly in a heterogeneous reservoir. The transient data, when available, may propagate deep into a reservoir up to kilometers, and the actual reservoir conditions can be sensed from far-away locations. The available transient data can be incorporated into the geological model, and reservoir properties are adjusted in compliance with the transient data. After incorporating the transient data into the geological model, the resulting geological model is considered a dynamic or transient model.

[0046] In some examples, a multi-layer transient model (e.g., a sixteen-layer transient model) is built based on a geological model. FIG. 5 illustrates an example multilateral well 502 placed on a multi-layer transient model 504 representing a reservoir. The geometrical parameters of the multilateral well 502 are optimized, and the controller 1500 can place / design the multilateral well 502 to achieve the maximum productivity / injectivity index.

[0047] At 304, after building the transient model from the geological model, the controller 1500 performs Quality assurance and quality control (QAQC) of the transient model with reference to input well and reservoir data or properties. During QAQC operations, practitioners can check if all the input well and reservoir data as shown in FIG. 4 are incorporated into the transient model correctly, and if the interpolation correlations are working as expected. Practitioners can check if all the geological features (barriers, faults, fractures, tight layers, etc.) that are derived from seismic and geology data analysis are incorporated correctly. Practitioners can check if reservoir properties (permeability, porosity, fluids saturation, saturation functions, relative permeability, fluids contacts, reservoir initial conditions) from the petrophysical log data (corrected based on core data if available), PVT data based on the collected samples and well data (perforations, geometry, production rates, etc.) are correct. In some implementations, there can be multiple wells in a geological model. Practitioners can check if the well completion and production data agree with the input well and reservoir properties and if they are defined correctly. QAQC can be performed based on the input data from each well in the geological model having a similar behavior and agreeing with the input well and reservoir data at respective well locations. QAQC of the transient model is performed with reference to input well and reservoir properties, to ensure that the input data is accurate and consistent with the well and reservoir configuration.

[0048] QAQC is performed to check that the input data, for example, well geometry, PVT, and production / injection, are added in order and that the measurement units are consistent and correct. For example, a depth unit in a well geometry is mistakenly selected in “meters” instead of “feet” when inputting the well data. As such, the well is thus placed at a distance away from the target reservoir. Upon completion of QAQC, such incoherence of the input data can be identified and rectified.

[0049] At 306, the controller 1500 checks if the transient model is acceptable after performing the QAQC and the well and reservoir data in the transient model agree with the input data, the controller 1500 performs 310. If the transient model is unacceptable, the controller 1500 performs 308 to adjust or correct the well and reservoir properties in the transient model. Otherwise, errors in the well and reservoir properties may lead to misleading results and interpretations.

[0050] In some implementations, if the actual recorded transient data, whenever available in offset or analogue wells, and the transient model pressure response are within a + / −5% difference, the transient model is considered acceptable. As an example, the reservoir properties are adjusted until the difference between the actual recorded pressure and the transient model pressure response is within + / −5%. The transient model pressure response is compared with the actual recorded transient data to demonstrate how the transient model is different from the original geological model. The actual (in-situ) reservoir properties are different from those of reservoir properties in the geological model because the reservoir is heterogeneous. By complying with the transient data, whenever available in offset or analogue wells, reservoir properties in the geological model are altered and corrected accordingly. After correcting the reservoir properties, the transient model pressure response matches with the actual transient data.

[0051] At 308, if the transient model is inconsistent with the input well and reservoir data, the controller 1500 adjusts the reservoir and well properties in the transient model according to the actual input well and reservoir data. After adjusting the well and reservoir properties in the geological model, the controller 1500 performs QAQC 304 again. Operations 306, 308, and 304 are iteratively performed until an acceptable transient model is built.

[0052] At 310, upon building the acceptable transient model, the controller 1500 runs a simulation to obtain a well location for drilling the multilateral well. The controller 1500 places a multilateral well along a proposed well trajectory and at the proposed location in the transient model utilizing a reservoir simulator. The controller 1500 runs a simulation by using a target production rate (e.g., a target production rate of 1,000 stock tank barrels per day (STB / D)) as a constraint. The controller 1500 can obtain a pressure response at the proposed location.

[0053] At 312, the controller 1500 evaluates the simulation result to determine whether the well can continuously produce hydrocarbon at the targeted production rate. If the simulation result suggests that the proposed multilateral well location can achieve the target production rate, the controller 1500 performs 316. Persons skilled in the art are able to determine if the well is capable of producing at the target production rate by examining the transient model or a simulated pressure response generated as an output of the transient model. The simulated pressure at any point in time is required not to fall below a predetermined pressure level based on fluid properties or other operational constraints. If the simulation result suggests that the proposed multilateral well location cannot achieve the target production rate, the controller 1500 performs 314 to adjust or move the well location.

[0054] At 314, if the proposed multilateral well location cannot achieve the target production rate, the controller 1500 adjusts or moves the well location in the transient model from the previously proposed location. The controller 1500 places the multilateral well at a new location, and runs a simulation 310 again to evaluate the new well location. The controller 1500 re-runs the simulation on the transient model by using the target production rate as a constraint to generate a pressure response (i.e., a simulated pressure over time) from the transient model for the new well location. Persons skilled in the art are able to determine if the well is capable of producing at the target production rate by examining the model or a simulated pressure response generated as an output of the transient model. The simulated pressure at any point in time is required not to fall below a predetermined pressure level based on reservoir properties, fluid properties or other operational constraints. If the new well location can achieve the production rate, the controller 1500 moves to 316; otherwise the controller 1500 iteratively adjusts the well location in the transient model until the target production rate can be satisfied (e.g., the production rate is equivalent to or within a predetermined range at or near the target production rate). Operations 310, 312, and 314 are iteratively performed until a final location meeting the target production rate is identified.

[0055] At 316, after determining the well location, the controller 1500 provides multiple lateral spacing options between the lateral sections (e.g., dual-lateral sections or tri-lateral sections) based on the transient model, offset wells nearby, and well configurations (e.g., dual-lateral sections, tri-lateral sections, or multiple lateral sections).

[0056] At 318, the controller 1500 runs simulation scenarios on the transient model for the multiple lateral spacing options and configurations, respectively. Each simulation scenario uses a target production rate as a constraint, and has a multilateral well placed at the final location determined at 310, 312, and 314. Each simulation scenario corresponds to a different lateral spacing and / or configuration. The controller 1500 adds a build-up period at the end of each simulation scenario for calculating PI according to Equation (1).PI=qpr-pwf(1)

[0057] Where q is production rate (e.g., barrels of oil per day), pr is reservoir pressure, and pwf is bottom-hole flowing pressure.

[0058] The build-up period refers to the duration during which the well is shut in following a certain duration of production. After shutting in the well to build up pressure, the reservoir pressure tends to reach its original or initial condition. The time required for any reservoir to reach its initial condition depends on its characteristics; for example, a good-quality reservoir (e.g., a homogeneous reservoir) reaches its original condition faster compared to a poor-quality reservoir (e.g., a heterogeneous reservoir). The change in reservoir pressure due to shutting in the well and production rates can be used to calculate the PI.

[0059] In some examples, the build-up period is long enough to achieve the late radial-flow regime on a log-log plot. Persons skilled in the art are able to determine if the build-up period is long enough. Interference between the lateral sections may mask the log-log plot data, which may impact PI calculation.

[0060] At 320, the controller 1500 calculates the PI for each simulation scenario by using the drawdown pressure response and build-up pressure response. Prior to calculating the PI, the controller 1500 generates a log-log plot from the build-up pressure response to ensure that the well has achieved the late radial-flow regime. The late radial-flow regime is a phase in the pressure transient analysis of a well where the pressure response truly represents the reservoir behaviors and the in-situ properties thereof.

[0061] In a homogenous reservoir, the relationship between PI and the lateral spacing can be linear after overcoming the interference between the lateral sections. By contrast, in a heterogeneous reservoir, the PI response can be nonlinear. Well configuration (the number of lateral sections) can also impact the PI values.

[0062] The build-up pressure response refers to a rise in well pressure as a function of time observed after a well is shut in or after the production rate is reduced. The build-up pressure response refers to a changing pressure at a downhole location in the well over time when the well is shut in after a certain period of production. During the build-up period, the well is subject to a zero-production rate. The pressure drawdown is a difference between the original reservoir pressure and the current flowing wellbore pressure. This pressure difference or drawdown at a given time drives fluids out of the reservoir into the wellbore. The drawdown period is the duration of the well when it is in production, and the build-up period is the duration when the well is shut in following the production.

[0063] At 322, the controller 1500 selects a lateral spacing from the multiple lateral spacing options and well configuration based on PI values. In some examples, a dual-lateral well may perform better in terms of PI than a tri-lateral well.

[0064] At 324, After selecting the lateral spacing and well configuration, the controller 1500 runs simulation scenarios for multiple well length options. An optimal well length can enable better reservoir contacts. The controller 1500 runs simulation scenarios by adding a build-up period at the end of the production period. The build-up period is long enough to achieve the late radial-flow regime on the log-log plot (a plot of pressure change versus time). Interference between the lateral sections may mask the log-log plot of pressure response, which may impact the calculation of PI.

[0065] At 326, the controller 1500 calculates and compares the PI for each well length option using the drawdown and build-up pressure responses. Before calculating the PI, the controller 1500 generates the log-log plot from the build-up pressure response. Persons skilled in the art understand that the well is subject to the late radial-flow regime. The controller 1500 selects the optimal well length corresponding to the largest PI value, from the multiple well length options, for the multilateral well. The selected well length can be practically achievable in the technological and geological environment. The multilateral well with the selected well length does not impact the offset wells.

[0066] At 328, the controller 1500 generates a virtual multilateral well at the selected well location, lateral spacing, and configuration to obtain the maximum hydrocarbon recovery.Subprocess 300C

[0067] In some implementations, to maintain the reservoir pressure and improve the oil recovery, a reservoir can employ enhanced oil recovery techniques by injecting different fluids into the reservoir. The fluid injection provides pressure support to a producer (e.g., a multilateral well that produces hydrocarbons), displaces hydrocarbons, and sweeps the hydrocarbons toward the producer.

[0068] At 330, the controller 1500 places a virtual injection well at a certain distance from the producer well (e.g., a multilateral well) and obtains an injection pressure response and water cut at the producer well. The controller 1500 runs a sensitivity analysis for multiple spacing options between the injector well (an injection well that injects fluids into the reservoir) and the producer well by moving the injector well close to or far away from the producer well and records injection pressure responses and water cut responses at the producer well.

[0069] At 332, the controller 1500 compares the pressure response and water cut responses for multiple injector-to-producer spacing options. An injector well close to the producer well can have an injection pressure response fast. A closer injector well may trigger an early water breakthrough and a high water cut at the producer well as well.

[0070] At 334, the controller 1500 selects a spacing from the multiple spacing options between the producer well and the injector well based on pressure response and water cut responses.

[0071] The example process 300 provides computer-aided techniques for geometrically optimizing a multilateral well. Multiple geometrical optimizations (selecting geometrical parameters) are performed around each main wellbore to place the lateral sections and to determine the number of lateral sections. The geometrical optimizations can minimize the competition among the lateral sections and maximize the drainage area, thereby increasing the well productivity index. As to a permeable reservoir, interference / competition among the lateral sections occurs fast. As to a tight or low-quality reservoir, the occurrence of interference / competition is delayed. The well productivity index is calculated for each simulation scenario, and a productivity index graph is generated as a measure of performance of the well quantitatively against each geometrical parameter based on the transient model. Graphical presentation of the productivity index can facilitate the determination of the optimal multilateral well design. Additional sensitivity analysis is performed to show the impact of reservoir heterogeneity, lateral-section lengths, lateral spacing, number of lateral sections, and the impact of offset producers / injectors.

[0072] The example process 300 can build a transient model using a geological model. The transient model can be built for any type of reservoir (homogeneous or heterogeneous) based on the reservoir description and properties. After building the transient model, dynamic production data (e.g., pressure response, production rate), whenever available in offset or analogue wells, is incorporated into the model, and simulation is run directly on this transient model. PI is calculated for each simulation scenario based on simulation responses (e.g., pressure responses), which are generated for different well locations, multilateral spacings, configurations, and well lengths. Before calculating the PI from drawdown pressure response and build-up pressure response, the pressure derivative for the simulated pressure is made on the log-log plot to confirm that the interference between the lateral is not impacting the build-up pressure response or that the build-up period has passed the interference region and achieved the late radial flow regime. After achieving satisfactory build-up pressure response, the controller 1500 compares PI values in terms of geometrical parameters of a multilateral well, such as lateral spacing, configuration (the number of lateral sections), and well length. As to a depleted reservoir, the spacing between offset injectors and the multilateral well can be optimized or determined by estimating injection well responses and water cut responses.Identify Optimal Location

[0073] Prior to the optimization of the geometrical parameters of a multilateral well, the controller 1500 selects a well location that meets a target production rate. FIG. 6 illustrates multiple locations 602, 604, 606, 608, and 610 for determining an optimized location to drill a multilateral well, according to some implementations. The controller 1500 can place a virtual multilateral well at the proposed location 602 and multiple locations 604, 606, 608, and 610 in the vicinity of the proposed location 602 and simulate production rates, respectively. The controller 1500 can select the optimal location from the multiple locations 602, 604, 606, 608, and 610.

[0074] FIG. 7 illustrates pressure response and production rate when drilling a multilateral well at proposed location 602, according to some implementations. As shown in FIG. 7, the multilateral well at location 602 produces more water than oil. Thus, location 602 is not an optimal location for drilling the multilateral well. The multilateral well is placed at locations 602, 604, 606, 608, and 610 to obtain production rate and pressure response, respectively. Location 606 is selected as the optimal location where the multilateral well can meet a production target.

[0075] FIG. 8 illustrates pressure response and production rate when drilling a multilateral well at location 606, according to some implementations. The transient response, including pressure response and production rate, is output by a transient model. As shown in FIG. 8, the multilateral well flows at specified oil and water production rates for a certain time period that is followed by a shut-in period. FIG. 8 also shows simulated flowing and shut-in pressures. These pressures are utilized in computing the productivity index of the multilateral well.Identify Optimal Lateral Spacing and Configuration

[0076] After selecting the well location, the controller 1500 selects an optimal spacing between the lateral sections to manage competition in the drainage area. In the drainage area, each lateral section tries to expand its drainage territory. All the lateral sections may compete for fluid extraction from the same zone. Competition in this drainage area can impact the PI. The objective of the optimal multilateral well is to acquire the maximum reservoir contact and PI. A multilateral well can perform better when draining from a non-competing drainage area. The selection of an optimal spacing between the lateral sections and an appropriate configuration with the number of lateral sections can optimize the drainage area. Simulation scenarios are performed for different configurations (the number of lateral sections) and spacing options.

[0077] FIG. 9 illustrates different lateral configurations of lateral sections in a heterogeneous reservoir, according to some implementations. As shown in FIG. 9, the multilateral well includes two lateral sections 902 or three lateral sections 904. FIG. 10 illustrates a PI graph with respect to lateral spacings for different lateral configurations, according to some implementations.

[0078] A lateral configuration is associated with heterogeneity due to reservoir geology. In some implementations, compared to a tri-lateral well, a dual-lateral well may achieve a better PI if the reservoir quality is degrading on one side of the proposed well location. Compared to a tri-lateral well, the dual-lateral well can save resources, including manpower and expenses.

[0079] As shown in curve 1002 representing a tri-lateral well of FIG. 10, PI increases by about 70% with respect to a lateral spacing increasing from 100 meters to 400 meters. When the lateral spacing increases from 400 meters to 600 meters, PI only increases by 10%. FIG. 10 suggests that any increase in lateral spacing further than 400 meters only adds marginal PI while occupying more reservoir area laterally. Lateral coverage of the reservoir area while adding marginal PI may prevent drilling more wells in the field, thereby suppressing reservoir recovery. FIG. 10 suggests that a lateral spacing of 400 meters is the optimal option. With this spacing of 400 meters, the lateral interference is minimal, and the competition in the drainage area is also minimized. The curve 1002 shows the lowest productivity index at 100 meters spacing due to pressure interference of lateral sections. Because all the lateral sections are trying to produce from the same drainage area, the well PI is impacted negatively. As the other two lateral sections L2 and L3 move away from L1, the pressure interference gets less. Less pressure interference can reduce the competition in the drainage area, thereby increasing the productivity index.

[0080] Referring to curve 1004 of FIG. 10, as to a dual lateral well with lateral sections L1 and L2, the PI value almost doubles when the lateral spacing changes from 100 meters to 600 meters, even though the PI value is less than that of the tri-lateral well. Referring to curve 1006 of FIG. 10, the dual lateral well with lateral sections L1 and L3 shows a poor response in PI, and the PI decreases as the lateral spacing increases. The curve 1006 suggests that the reservoir heterogeneity plays a dominant role as the reservoir quality degrades towards the lateral section L3. Any increase in lateral spacing of more than 400 meters between the lateral sections can impact PI. Curve 1006 shows that increasing the lateral spacing over 400 meters corresponds to a decrease in the PI, and suggests that the lateral spacing over 400 meters places the lateral section L3 in a lower-quality reservoir area. The curve 1004 of the dual lateral sections L1 and L2 suggests that an increase in the lateral spacing of more than 400 meters can bring an increase in PI, while the curve 1006 of the lateral sections L1 and L3 suggests an opposite trend.

[0081] The controller 1500 can identify well configuration (the number of lateral sections) and lateral spacing corresponding to the optimal PI. In the example of FIG. 10, the lateral spacing of 400 meters is optimal because a further increase of more than 400 meters in the lateral spacing provides a marginal increase in PI while covering more area of the reservoir. The coverage of more areas of the reservoir can result in fewer wells being drilled in the oil and gas field, thereby impacting the reservoir recovery.Identify Optimal Well Length

[0082] After identifying the optimal configuration and lateral spacing based on PI, the controller 1500 determines a well length (the length of each lateral section) to further maximize the PI. Well length plays a major role in well productivity while directly impacting drilling costs. The determined well length is required to be accountable to economics. As to a good-quality, homogeneous reservoir, an increase in a well length leads to a high PI. As to a highly heterogeneous reservoir, an increase in a well length may not increase the PI. If a reservoir quality degrades, an increase in a well length may reduce or not change the PI. A sensitivity analysis for the well length can be performed to identify the optimal well length. Reservoir quality is a factor to be considered when performing the sensitivity analysis for well length. In a good-quality, homogeneous reservoir, interference between lateral sections can be perceived faster compared to a lower-quality, heterogeneous reservoir. The interference between the lateral sections may cause competition, thereby reducing the PI of the well. Thus, in some examples, an increase in well length does not increase PI due to interference.

[0083] FIG. 11 illustrates a PI graph with respect to lateral lengths, according to some implementations. As shown in FIG. 11, sensitivity analyses are performed for different well lengths. The X-axis of FIG. 11 represents the total length of a well (the total length of lateral sections of a well). As an example, each lateral section has the same length. The PI graph suggests that a tri-lateral well with a 21,000 ft total length (i.e., 7,000 ft length for each lateral section) is the optimal option considering both PI and drilling costs. The dual-lateral well with a 20,000 ft total length (i.e., 10,000 ft length for each lateral section) corresponds to a similar PI (the PI corresponds to the tri-lateral well with a 21,000 ft total length). However, considering operational limitations and future maintenance, such a long well may not be feasible. Therefore, the optimal well length is 7,000 ft for each lateral section, and the tri-lateral well is the optimal geometrical configuration.Identify Injector to Producer Spacing

[0084] To maintain reservoir pressure and improve oil recovery from an existing reservoir, oil recovery techniques are used by injecting different fluids into the reservoir. The recovery techniques are intended to provide pressure support to a producer well, displace hydrocarbons, and sweep them toward the producer well. The spacing between an injector well and the producer well is associated with the pressure response on the producer well. The spacing between an injector well and the producer can be determined based on the pressure response.

[0085] The injection pressure response and the level of pressure support are incorporated to maximize the PI and achieve the maximum recovery target. Sensitivity analyses are performed considering variations of the injector to producer spacing and injection rate. FIG. 12 illustrates a pressure response graph with respect to injector-to-producer spacings (e.g., 250 meters, 500 meters, 750 meters, 1000 meters), according to some implementations. If the injector-to-producer spacing is 500 meters, the producer well (Well 3) can support the highest pressure due to the least pressure drawdown at the producer well. As shown in FIG. 12, pressure response for each spacing and production rate at the producer well (Well 3) are presented in FIG. 12. In some implementations, water production at the producer well is also considered while determining the spacing between the injector well and the producer well. The spacing between the injector well and the producer well is required to allow a tolerable amount of water cut at the producer well. Persons skilled in the art can determine the optimal spacing based on the degree of pressure support at the producer well, the water cut, and the time delay of the first episode of water production at the producer well. In the example of FIG. 12, the optimal spacing is 750 meters, which is a tradeoff between a loss of some pressure support at the expense of less water cut and delayed water production at the producer well.

[0086] FIG. 13 illustrates another example process of determining an optimized location and optimized geometrical parameters to drill a multilateral well in a reservoir, according to some implementations. Process 1300 is described as being performed by a computing device including one or more processors or a controller, such as controller 1500 of FIG. 15. The example process 1300 shown in FIG. 13 can be modified or reconfigured to include additional, fewer, or different steps (not shown in FIG. 13), which can be performed in the order shown or in a different order.

[0087] At 1302, the controller 1500 builds a multi-layer transient model representing the reservoir based on a geological model. For example, the transient model can include 16 layers. While describing the reservoir geology in the best possible way, persons skilled in the art would intend to minimize the number of layers in the geological model or the transient model to minimize a computational load.

[0088] At 1304, the controller 1500 determines a location at the reservoir for placing at least one multilateral well by executing multiple simulation scenarios at the multi-layer transient model. In each simulation scenario, the at least one multilateral well is placed at a different candidate location. In some implementations, multiple candidate locations are provided and the controller 1500 selects the optimal location from the multiple candidate locations. The multilateral well is predicted to produce hydrocarbon at a target or desired production rate if the multilateral well is placed at the optimal location.

[0089] At 1306, the controller 1500 determines a lateral spacing between lateral sections of the multilateral well and a number of lateral sections by executing the multiple simulation scenarios that produce hydrocarbons at a target production rate. In each simulation scenario, the multilateral well is placed at the optimal location determined at 1304 and the multilateral well is simulated with a different combination of candidate lateral spacing and the number of lateral sections. A PI is calculated as a quantitative measure of the well performance for each simulation scenario. In some implementations, multiple candidate lateral spacings are provided and the controller 1500 selects the optimal lateral spacing from the multiple lateral spacings. The selection is based on a balance between PI and drilling costs.

[0090] At 1308, the controller 1500 determines a well length for each lateral section by executing the multiple simulation scenarios that produce hydrocarbons at a target production rate. In each simulation scenario, the multilateral well is placed at the optimal location determined at 1304 and the multilateral well is simulated with a different candidate well length and the optimal candidate lateral spacing and the optimal number of lateral sections determined at 1306. A PI is calculated as a quantitative measure of the well performance for each simulation scenario. In some implementations, multiple candidate well lengths are provided and the controller 1500 selects the optimal well length from the multiple well lengths. The selection is based on a balance between PI and drilling costs.

[0091] At 1310, the controller 1500 determines a spacing between the multilateral well and an injection well based on a pressure response and a water cut response at the multilateral well. In some implementations, multiple candidate spacings are provided and the controller 1500 selects the optimal spacing from the multiple spacings. The selection is based on a pressure response and a water cut response at the multilateral well.

[0092] At 1312, the controller 1500 places the multilateral well having the optimal lateral spacing, the optimal number of lateral sections, the optimal well length, and the optimal spacing between the multilateral well and an injection well at the optimal location in a simulation scenario. In some embodiments, the multilateral well with the optimal lateral spacing, the optimal number of lateral sections, and the optimal well length at the optimal location of a simulation scenario is rendered using a display device. In some embodiments, a real-world multilateral well is drilled at the reservoir with the optimal lateral spacing, the optimal number of lateral sections, and the optimal well length at the optimal location as simulated in the simulation scenario.

[0093] FIG. 14 illustrates hydrocarbon production operations 1400 that include both one or more field operations 1410 and one or more computational operations 1412, which exchange information and control exploration for the production of hydrocarbons. In some implementations, outputs of techniques of the present disclosure can be performed before, during, or in combination with the hydrocarbon production operations 1400, specifically, for example, either as field operations 1410 or computational operations 1412, or both.

[0094] Examples of field operations 1410 include forming / drilling a wellbore, hydraulic fracturing, producing through the wellbore, and injecting fluids (such as water) through the wellbore, to name a few. In some implementations, methods of the present disclosure can trigger or control the field operations 1410. For example, the methods of the present disclosure can generate data from hardware / software including sensors and physical data gathering equipment (e.g., seismic sensors, well logging tools, flow meters, and temperature and pressure sensors). The methods of the present disclosure can include transmitting the data from the hardware / software to the field operations 1410 and responsively triggering the field operations 1410 including, for example, generating plans and signals that provide feedback to and control physical components of the field operations 1410. Alternatively or in addition, the field operations 1410 can trigger the methods of the present disclosure. For example, implementing physical components (including, for example, hardware, such as sensors) deployed in the field operations 1410 can generate plans and signals that can be provided as input or feedback (or both) to the methods of the present disclosure.

[0095] Examples of computational operations 1412 include one or more computer systems 1420 that include one or more processors and computer-readable media (e.g., non-transitory computer-readable media) operatively coupled to the one or more processors to execute computer operations to perform the methods of the present disclosure. The computational operations 1412 can be implemented using one or more databases 1418, which store data received from the field operations 1410 and / or generated internally within the computational operations 1412 (e.g., by implementing the methods of the present disclosure) or both. For example, the one or more computer systems 1420 process inputs from the field operations 1410 to assess conditions in the physical world, the outputs of which are stored in the databases 1418. For example, seismic sensors of the field operations 1410 can be used to perform a seismic survey to map subterranean features, such as facies and faults. In performing a seismic survey, seismic sources (e.g., seismic vibrators or explosions) generate seismic waves that propagate in the Earth, and seismic receivers (e.g., geophones) measure reflections generated as the seismic waves interact with boundaries between layers of a subsurface formation. The source and received signals are provided to the computational operations 1412 where they are stored in the databases 1418 and analyzed by the one or more computer systems 1420.

[0096] In some implementations, one or more outputs 1422 generated by the one or more computer systems 1420 can be provided as feedback / input to the field operations 1410 (either as direct input or stored in the databases 1418). The field operations 1410 can use the feedback / input to control physical components used to perform the field operations 1410 in the real world.

[0097] For example, the computational operations 1412 can process the seismic data to generate three-dimensional (3D) maps of the subsurface formation. The computational operations 1412 can use these 3D maps to provide plans for locating and drilling exploratory wells. In some operations, the exploratory wells are drilled using logging-while-drilling (LWD) techniques which incorporate logging tools into the drill string. LWD techniques can enable the computational operations 1412 to process new information about the formation and control the drilling to adjust to the observed conditions in real time.

[0098] The one or more computer systems 1420 can update the 3D maps of the subsurface formation as information from one exploration well is received, and the computational operations 1412 can adjust the location of the next exploration well based on the updated 3D maps. Similarly, the data received from production operations can be used by the computational operations 1412 to control components of the production operations. For example, production well and pipeline data can be analyzed to predict slugging in pipelines leading to a refinery, and the computational operations 1412 can control machine operated valves upstream of the refinery to reduce the likelihood of plant disruptions that run the risk of taking the plant offline.

[0099] In some implementations of the computational operations 1412, customized user interfaces can present intermediate or final results of the above-described processes to a user. Information can be presented in one or more textual, tabular, or graphical formats, such as through a dashboard. The information can be presented at one or more on-site locations (such as at an oil well or other facility), on the Internet (such as on a webpage), on a mobile application (or app), or at a central processing facility.

[0100] The presented information can include feedback, such as changes in parameters or processing inputs, that the user can select to improve a production environment, such as in the exploration, production, and / or testing of petrochemical processes or facilities. For example, the feedback can include parameters that, when selected by the user, can cause a change to, or an improvement in, drilling parameters (including drill bit speed and direction) or overall production of a gas or oil well. The feedback, when implemented by the user, can improve the speed and accuracy of calculations, streamline processes, improve models, and solve problems related to efficiency, performance, safety, reliability, costs, downtime, and the need for human interaction.

[0101] In some implementations, the feedback can be implemented in real-time, such as to provide an immediate or near-immediate change in operations or in a model. The term real-time (or similar terms as understood by one of ordinary skill in the art) means that an action and a response are temporally proximate such that an individual perceives the action and the response occurring substantially simultaneously. For example, the time difference for a response to display (or for an initiation of a display) of data following the individual's action to access the data can be less than 1 millisecond (ms), less than 1 second(s), or less than 5 s. While the requested data need not be displayed (or initiated for display) instantaneously, it is displayed (or initiated for display) without any intentional delay, taking into account processing limitations of a described computing system and time required to, for example, gather, accurately measure, analyze, process, store, or transmit the data.

[0102] Events can include readings or measurements captured by downhole equipment such as sensors, pumps, bottom hole assemblies, or other equipment. The readings or measurements can be analyzed at the surface, such as by using applications that can include modeling applications and machine learning. The analysis can be used to generate changes to settings of downhole equipment, such as drilling equipment. In some implementations, values of parameters or other variables that are determined can be used automatically (such as through using rules) to implement changes in oil or gas well exploration, production / drilling, or testing. For example, outputs of the present disclosure can be used as inputs to other equipment and / or systems at a facility. This can be especially useful for systems or various pieces of equipment that are located several meters or several miles apart, or are located in different countries or other jurisdictions.

[0103] FIG. 15 is a schematic illustration of an example controller 1500 (or control system) that enables an example system to detect water leaks / loss and recommend corrective repair actions, according to some implementations. For example, the controller 1500 may be operable according to the processes 300 and 1300 of FIGS. 3 and 13. The controller 1500 is intended to include various forms of digital computers, such as printed circuit boards (PCB), processors, digital circuitry, or otherwise parts of a system for supply chain alert management. Additionally the system can include portable storage media, such as, Universal Serial Bus (USB) flash drives. For example, the USB flash drives may store operating systems and other applications. The USB flash drives can include input / output components, such as a wireless transmitter or USB connector that may be inserted into a USB port of another computing device.

[0104] The controller 1500 includes a processor 1510, a memory 1520, a storage device 1530, and an input / output interface 1540 communicatively coupled with input / output devices 1560 (for example, displays, keyboards, measurement devices, sensors, valves, pumps). Each of the components 1510, 1520, 1530, and 1540 are interconnected using a system bus 1550. The processor 1510 is capable of processing instructions for execution within the controller 1500. The processor may be designed using any of a number of architectures. For example, the processor 1510 may be a CISC (Complex Instruction Set Computers) processor, a RISC (Reduced Instruction Set Computer) processor, or a MISC (Minimal Instruction Set Computer) processor.

[0105] In one implementation, the processor 1510 is a single-threaded processor. In another implementation, the processor 1510 is a multi-threaded processor. The processor 1510 is capable of processing instructions stored in the memory 1520 or on the storage device 1530 to display graphical information for a user interface on the input / output interface 1540.

[0106] The memory 1520 stores information within the controller 1500. In one implementation, the memory 1520 is a computer-readable medium. In one implementation, the memory 1520 is a volatile memory unit. In another implementation, the memory 1520 is a non-volatile memory unit.

[0107] The storage device 1530 is capable of providing mass storage for the controller 1500. In one implementation, the storage device 1530 is a computer-readable medium. In various different implementations, the storage device 1530 may be a floppy disk device, a hard disk device, an optical disk device, or a tape device.

[0108] The input / output interface 1540 provides input / output operations for the controller 1500. In one implementation, the input / output devices 1560 include a keyboard and / or pointing device. In another implementation, the input / output devices 1560 includes a display unit for displaying graphical user interfaces.

[0109] There can be any number of controllers 1500 associated with, or external to, a computer system containing controller 1500, with each controller 1500 communicating over a network. Further, the terms “client,”“user,” and other appropriate terminology can be used interchangeably, as appropriate, without departing from the scope of the present disclosure. Moreover, the present disclosure contemplates that many users can use one controller 1500, and one user can use multiple controllers 1500.EMBODIMENTS / EXAMPLES

[0110] According to some non-limiting embodiments or examples, provided is a computer-implemented method for placing at least one multilateral well in a reservoir, comprising: building a multi-layer transient model representing the reservoir based on a geological model; determining a location at the reservoir for placing the at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0111] According to some non-limiting embodiments or examples, provided is an apparatus comprising a non-transitory, computer readable, storage medium that stores instructions that, when executed by at least one processor, cause the at least one processor to perform operations comprising: building a multi-layer transient model representing a reservoir based on a geological model; determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0112] According to some non-limiting embodiments or examples, provided is a system, comprising: one or more memory modules; and one or more hardware processors communicably coupled to the one or more memory modules, the one or more hardware processors configured to execute instructions stored on the one or more memory modules to perform operations comprising: building a multi-layer transient model representing a reservoir based on a geological model; determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0113] Further non-limiting aspects or embodiments are set forth in the following numbered embodiments:

[0114] Embodiment 1: A computer-implemented method for placing at least one multilateral well in a reservoir, comprising: building a multi-layer transient model representing the reservoir based on a geological model; determining a location at the reservoir for placing the at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0115] Embodiment 2: The computer-implemented method of Embodiment 1, further comprising determining a spacing between the at least one multilateral well and an injection well based on a pressure response and a water cut response at the at least one multilateral well.

[0116] Embodiment 3: The computer-implemented method of Embodiment 2, further comprising: receiving multiple candidate spacings between the at least one multilateral well and the injection well; performing a sensitivity analysis for each candidate spacing to obtain an injection pressure response and a water cut response at the at least one multilateral well; and selecting the spacing from the multiple candidate spacings based on the injection pressure response and the water cut response.

[0117] Embodiment 4: The computer-implemented method of any one of Embodiments 1-3, building the multi-layer transient model further comprising: providing reservoir data including one or more of geological data, geophysical data, petrophysical data, pressure, volume and temperature (PVT) data, reservoir initial conditions, fluid-contact data, reference point, capillary pressure, relative permeability and well data including one or more of a proposed multilateral well trajectory, an injection well trajectory, pressure response data, production rates to the geological model; and performing Quality assurance and quality control (QAQC) of the multi-layer transient model with reference to the reservoir data and the well data.

[0118] Embodiment 5: The computer-implemented method of any one of Embodiments 1-4, determining the location further comprising: executing a first simulation scenario with the at least one multilateral well placed at an initial location; in response to the at least one multilateral well failing to satisfy the target production rate at the initial location, adjusting the initial location and iteratively executing a new first simulation scenario at adjusted locations until the at least one multilateral well satisfies the target production rate; and determining that the adjusted location is the location for placing the at least one multilateral well.

[0119] Embodiment 6: The computer-implemented method of any one of Embodiments 1-5, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising: receiving multiple candidate lateral spacings for the at least one multilateral well; performing a simulation scenario for each candidate lateral spacing; calculating the first PI for each candidate lateral spacing; and selecting the lateral spacing from the multiple candidate lateral spacings based on the first PI.

[0120] Embodiment 7: The computer-implemented method of Embodiment 6, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising: prior to calculating the first PI, generating a log-log plot to identify a late radial-flow regime.

[0121] Embodiment 8: The computer-implemented method of any one of Embodiments 1-7, determining the well length for each lateral section further comprising: receiving multiple candidate well lengths for the at least one multilateral well; performing a simulation scenario for each candidate well length; calculating the second PI for each candidate well length; and selecting the well length from the multiple candidate well lengths based on the second PI.

[0122] Embodiment 9: An apparatus comprising a non-transitory, computer readable, storage medium that stores instructions that, when executed by at least one processor, cause the at least one processor to perform operations comprising: building a multi-layer transient model representing a reservoir based on a geological model; determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0123] Embodiment 10: The apparatus of Embodiment 9, the operations further comprising determining a spacing between the at least one multilateral well and an injection well based on a pressure response and a water cut response at the at least one multilateral well.

[0124] Embodiment 11: The apparatus of Embodiment 10, the operations further comprising: receiving multiple candidate spacings between the at least one multilateral well and the injection well; performing a sensitivity analysis for each candidate spacing to obtain an injection pressure response and a water cut response at the at least one multilateral well; and selecting the spacing from the multiple candidate spacings based on the injection pressure response and the water cut response.

[0125] Embodiment 12: The apparatus of any one of Embodiments 9-11, building the multi-layer transient model further comprising: providing reservoir data including one or more of geological data, geophysical data, petrophysical data, pressure, volume and temperature (PVT) data, reservoir initial conditions, fluid-contact data, reference point, capillary pressure, relative permeability and well data including one or more of a proposed multilateral well trajectory, an injection well trajectory, pressure response data, production rates to the geological model; and performing Quality assurance and quality control (QAQC) of the multi-layer transient model with reference to the reservoir data and the well data.

[0126] Embodiment 13: The apparatus of any one of Embodiments 9-12, determining the location further comprising: executing a first simulation scenario with the at least one multilateral well placed at an initial location; in response to the at least one multilateral well failing to satisfy the target production rate at the initial location, adjusting the initial location and iteratively executing a new first simulation scenario at adjusted locations until the at least one multilateral well satisfies the target production rate; and determining that the adjusted location is the location for placing the at least one multilateral well.

[0127] Embodiment 14: The apparatus of any one of Embodiments 9-13, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising: receiving multiple candidate lateral spacings for the at least one multilateral well; performing a simulation scenario for each candidate lateral spacing; calculating the first PI for each candidate lateral spacing; and selecting the lateral spacing from the multiple candidate lateral spacings based on the first PI.

[0128] Embodiment 15: The apparatus of Embodiment 14, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising: prior to calculating the first PI, generating a log-log plot to identify a late radial-flow regime.

[0129] Embodiment 16: The apparatus of any one of Embodiments 9-15, determining the well length for each lateral section further comprising: receiving multiple candidate well lengths for the at least one multilateral well; performing a simulation scenario for each candidate well length; calculating the second PI for each candidate well length; and selecting the well length from the multiple candidate well lengths based on the second PI.

[0130] Embodiment 17: A system, comprising: one or more memory modules; and one or more hardware processors communicably coupled to the one or more memory modules, the one or more hardware processors configured to execute instructions stored on the one or more memory modules to perform operations comprising: building a multi-layer transient model representing a reservoir based on a geological model; determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; determining a well length for each lateral section of the at least one multilateral well based at least in part on second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; and drilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

[0131] Embodiment 18: The system of Embodiment 17, the operations further comprising determining a spacing between the at least one multilateral well and an injection well based on a pressure response and a water cut response at the at least one multilateral well.

[0132] Embodiment 19: The system of Embodiment 18, the operations further comprising: receiving multiple candidate spacings between the at least one multilateral well and the injection well; performing a sensitivity analysis for each candidate spacing to obtain an injection pressure response and a water cut response at the at least one multilateral well; and selecting the spacing from the multiple candidate spacings based on the injection pressure response and the water cut response.

[0133] Embodiment 20: The system of any one of Embodiments 17-19, determining the location further comprising: executing a first simulation scenario with the at least one multilateral well placed at an initial location; in response to the at least one multilateral well failing to satisfy the target production rate at the initial location, adjusting the initial location and iteratively executing a new first simulation scenario at adjusted locations until the at least one multilateral well satisfies the target production rate; and determining that the adjusted location is the location for placing the at least one multilateral well.

[0134] Implementations of the subject matter and the functional operations described in this specification can be implemented in digital electronic circuitry, in tangibly embodied computer software or firmware, in computer hardware, including the structures disclosed in this specification and their structural equivalents, or in combinations of one or more of them. Software implementations of the described subject matter can be implemented as one or more computer programs. Each computer program can include one or more modules of computer program instructions encoded on a tangible, non-transitory, computer-readable computer-storage medium for execution by, or to control the operation of, data processing apparatus. Alternatively, or additionally, the program instructions can be encoded in / on an artificially generated propagated signal. The example, the signal can be a machine-generated electrical, optical, or electromagnetic signal that is generated to encode information for transmission to suitable receiver apparatus for execution by a data processing apparatus. The computer-storage medium can be a machine-readable storage device, a machine-readable storage substrate, a random or serial access memory device, or a combination of computer-storage mediums.

[0135] The terms “data processing apparatus,”“computer,” and “electronic computer device” (or equivalent as understood by one of ordinary skill in the art) refer to data processing hardware. For example, a data processing apparatus can encompass all kinds of apparatus, devices, and machines for processing data, including by way of example, a programmable processor, a computer, or multiple processors or computers. The apparatus can also include special purpose logic circuitry including, for example, a central processing unit (CPU), a field programmable gate array (FPGA), or an application specific integrated circuit (ASIC). In some implementations, the data processing apparatus or special purpose logic circuitry (or a combination of the data processing apparatus or special purpose logic circuitry) can be hardware- or software-based (or a combination of both hardware- and software-based). The apparatus can optionally include code that creates an execution environment for computer programs, for example, code that constitutes processor firmware, a protocol stack, a database management system, an operating system, or a combination of execution environments. The present disclosure contemplates the use of data processing apparatuses with or without conventional operating systems, for example, LINUX, UNIX, WINDOWS, MAC OS, ANDROID, or IOS.

[0136] A computer program, which can also be referred to or described as a program, software, a software application, a module, a software module, a script, or code, can be written in any form of programming language. Programming languages can include, for example, compiled languages, interpreted languages, declarative languages, or procedural languages. Programs can be deployed in any form, including as stand-alone programs, modules, components, subroutines, or units for use in a computing environment. A computer program can, but need not, correspond to a file in a file system. A program can be stored in a portion of a file that holds other programs or data, for example, one or more scripts stored in a markup language document, in a single file dedicated to the program in question, or in multiple coordinated files storing one or more modules, sub programs, or portions of code. A computer program can be deployed for execution on one computer or on multiple computers that are located, for example, at one site or distributed across multiple sites that are interconnected by a communication network. While portions of the programs illustrated in the various figures may be shown as individual modules that implement the various features and functionality through various objects, methods, or processes, the programs can instead include a number of sub-modules, third-party services, components, and libraries. Conversely, the features and functionality of various components can be combined into single components as appropriate. Thresholds used to make computational determinations can be statically, dynamically, or both statically and dynamically determined.

[0137] The methods, processes, or logic flows described in this specification can be performed by one or more programmable computers executing one or more computer programs to perform functions by operating on input data and generating output. The methods, processes, or logic flows can also be performed by, and apparatus can also be implemented as, special purpose logic circuitry, for example, a CPU, an FPGA, or an ASIC.

[0138] Computers suitable for the execution of a computer program can be based on one or more of general and special purpose microprocessors and other kinds of CPUs. The elements of a computer are a CPU for performing or executing instructions and one or more memory devices for storing instructions and data. Generally, a CPU can receive instructions and data from (and write data to) a memory. A computer can also include, or be operatively coupled to, one or more mass storage devices for storing data. In some implementations, a computer can receive data from, and transfer data to, the mass storage devices including, for example, magnetic, magneto optical disks, or optical disks. Moreover, a computer can be embedded in another device, for example, a mobile telephone, a personal digital assistant (PDA), a mobile audio or video player, a game console, a global positioning system (GPS) receiver, or a portable storage device such as a universal serial bus (USB) flash drive.

[0139] Computer readable media (transitory or non-transitory, as appropriate) suitable for storing computer program instructions and data can include all forms of permanent / non-permanent and volatile / non-volatile memory, media, and memory devices. Computer readable media can include, for example, semiconductor memory devices such as random access memory (RAM), read only memory (ROM), phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), and flash memory devices. Computer readable media can also include, for example, magnetic devices such as tape, cartridges, cassettes, and internal / removable disks. Computer readable media can also include magneto optical disks and optical memory devices and technologies including, for example, digital video disc (DVD), CD ROM, DVD+ / −R, DVD-RAM, DVD-ROM, HD-DVD, and BLURAY. The memory can store various objects or data, including caches, classes, frameworks, applications, modules, backup data, jobs, web pages, web page templates, data structures, database tables, repositories, and dynamic information. Types of objects and data stored in memory can include parameters, variables, algorithms, instructions, rules, constraints, and references. Additionally, the memory can include logs, policies, security or access data, and reporting files. The processor and the memory can be supplemented by, or incorporated in, special purpose logic circuitry.

[0140] Implementations of the subject matter described in the present disclosure can be implemented on a computer having a display device for providing interaction with a user, including displaying information to (and receiving input from) the user. Types of display devices can include, for example, a cathode ray tube (CRT), a liquid crystal display (LCD), a light-emitting diode (LED), and a plasma monitor. Display devices can include a keyboard and pointing devices including, for example, a mouse, a trackball, or a trackpad. User input can also be provided to the computer through the use of a touchscreen, such as a tablet computer surface with pressure sensitivity or a multi-touch screen using capacitive or electric sensing. Other kinds of devices can be used to provide for interaction with a user, including to receive user feedback including, for example, sensory feedback including visual feedback, auditory feedback, or tactile feedback. Input from the user can be received in the form of acoustic, speech, or tactile input. In addition, a computer can interact with a user by sending documents to, and receiving documents from, a device that is used by the user. For example, the computer can send web pages to a web browser on a user's client device in response to requests received from the web browser.

[0141] The term “graphical user interface,” or “GUI,” can be used in the singular or the plural to describe one or more graphical user interfaces and each of the displays of a particular graphical user interface. Therefore, a GUI can represent any graphical user interface, including, but not limited to, a web browser, a touch screen, or a command line interface (CLI) that processes information and efficiently presents the information results to the user. In general, a GUI can include a plurality of user interface (UI) elements, some or all associated with a web browser, such as interactive fields, pull-down lists, and buttons. These and other UI elements can be related to or represent the functions of the web browser.

[0142] Implementations of the subject matter described in this specification can be implemented in a computing system that includes a back-end component, for example, as a data server, or that includes a middleware component, for example, an application server. Moreover, the computing system can include a front-end component, for example, a client computer having one or both of a graphical user interface or a Web browser through which a user can interact with the computer. The components of the system can be interconnected by any form or medium of wireline or wireless digital data communication (or a combination of data communication) in a communication network. Examples of communication networks include a local area network (LAN), a radio access network (RAN), a metropolitan area network (MAN), a wide area network (WAN), Worldwide Interoperability for Microwave Access (WIMAX), a wireless local area network (WLAN) (for example, using 802.11 a / b / g / n or 802.20 or a combination of protocols), all or a portion of the Internet, or any other communication system or systems at one or more locations (or a combination of communication networks). The network can communicate with, for example, Internet Protocol (IP) packets, frame relay frames, asynchronous transfer mode (ATM) cells, voice, video, data, or a combination of communication types between network addresses.

[0143] The computing system can include clients and servers. A client and server can generally be remote from each other and can typically interact through a communication network. The relationship of client and server can arise by virtue of computer programs running on the respective computers and having a client-server relationship. Cluster file systems can be any file system type accessible from multiple servers for read and update. Locking or consistency tracking may not be necessary since the locking of exchange file system can be done at application layer. Furthermore, Unicode data files can be different from non-Unicode data files.

[0144] While this specification contains many specific implementation details, these should not be construed as limitations on the scope of what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this specification in the context of separate implementations can also be implemented, in combination, in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any suitable sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.

[0145] Various components may be described as performing a task or tasks, for convenience in the description. Such descriptions should be interpreted as including the phrase “configured to.” Reciting a component that is configured to perform one or more tasks is expressly intended not to invoke 35 USC § 112(f) interpretation for that component.

[0146] Particular implementations of the subject matter have been described. Other implementations, alterations, and permutations of the described implementations are within the scope of the following claims as will be apparent to those skilled in the art. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. In certain circumstances, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and performed as deemed appropriate.

[0147] Moreover, the separation or integration of various system modules and components in the previously described implementations should not be understood as requiring such separation or integration in all implementations, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.

[0148] Accordingly, the previously described example implementations do not define or constrain the present disclosure. Other changes, substitutions, and alterations are also possible without departing from the spirit and scope of the present disclosure.

[0149] Furthermore, any claimed implementation is considered to be applicable to at least a computer-implemented method; a non-transitory, computer-readable medium storing computer-readable instructions to perform the computer-implemented method; and a computer system comprising a computer memory interoperably coupled with a hardware processor configured to perform the computer-implemented method or the instructions stored on the non-transitory, computer-readable medium.

[0150] Particular embodiments of the subject matter have been described. Other embodiments are within the scope of the following claims. For example, the actions recited in the claims can be performed in a different order and still achieve desirable results. As one example, some processes depicted in the accompanying figures do not necessarily require the particular order shown, or sequential order, to achieve desirable results.

Examples

embodiments / examples

EMBODIMENTS / EXAMPLES

[0110]According to some non-limiting embodiments or examples, provided is a computer-implemented method for placing at least one multilateral well in a reservoir, comprising: building a multi-layer transient model representing the reservoir based on a geological model; determining a location at the reservoir for placing the at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location; determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario; det...

Claims

1. A computer-implemented method for placing at least one multilateral well in a reservoir, comprising:building a multi-layer transient model representing the reservoir based on a geological model;determining a location at the reservoir for placing the at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location;determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario;determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; anddrilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

2. The computer-implemented method of claim 1, further comprising determining a spacing between the at least one multilateral well and an injection well based on a pressure response and a water cut response at the at least one multilateral well.

3. The computer-implemented method of claim 2, further comprising:receiving multiple candidate spacings between the at least one multilateral well and the injection well;performing a sensitivity analysis for each candidate spacing to obtain an injection pressure response and a water cut response at the at least one multilateral well; andselecting the spacing from the multiple candidate spacings based on the injection pressure response and the water cut response.

4. The computer-implemented method of claim 1, building the multi-layer transient model further comprising:providing reservoir data including one or more of geological data, geophysical data, petrophysical data, pressure, volume and temperature (PVT) data, reservoir initial conditions, fluid-contact data, reference point, capillary pressure, relative permeability and well data including one or more of a proposed multilateral well trajectory, an injection well trajectory, pressure response data, production rates to the geological model; andperforming Quality assurance and quality control (QAQC) of the multi-layer transient model with reference to the reservoir data and the well data.

5. The computer-implemented method of claim 1, determining the location further comprising:executing a first simulation scenario with the at least one multilateral well placed at an initial location;in response to the at least one multilateral well failing to satisfy the target production rate at the initial location,adjusting the initial location and iteratively executing a new first simulation scenario at adjusted locations until the at least one multilateral well satisfies the target production rate; anddetermining that the adjusted location is the location for placing the at least one multilateral well.

6. The computer-implemented method of claim 1, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising:receiving multiple candidate lateral spacings for the at least one multilateral well;performing a simulation scenario for each candidate lateral spacing;calculating the first PI for each candidate lateral spacing; andselecting the lateral spacing from the multiple candidate lateral spacings based on the first PI.

7. The computer-implemented method of claim 6, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising:prior to calculating the first PI, generating a log-log plot to identify a late radial-flow regime.

8. The computer-implemented method of claim 1, determining the well length for each lateral section further comprising:receiving multiple candidate well lengths for the at least one multilateral well;performing a simulation scenario for each candidate well length;calculating the second PI for each candidate well length; andselecting the well length from the multiple candidate well lengths based on the second PI.

9. An apparatus comprising a non-transitory, computer readable, storage medium that stores instructions that, when executed by at least one processor, cause the at least one processor to perform operations comprising:building a multi-layer transient model representing a reservoir based on a geological model;determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location;determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario;determining a well length for each lateral section of the at least one multilateral well based at least in part on a second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; anddrilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

10. The apparatus of claim 9, the operations further comprising determining a spacing between the at least one multilateral well and an injection well based on a pressure response and a water cut response at the at least one multilateral well.

11. The apparatus of claim 10, the operations further comprising:receiving multiple candidate spacings between the at least one multilateral well and the injection well;performing a sensitivity analysis for each candidate spacing to obtain an injection pressure response and a water cut response at the at least one multilateral well; andselecting the spacing from the multiple candidate spacings based on the injection pressure response and the water cut response.

12. The apparatus of claim 9, building the multi-layer transient model further comprising:providing reservoir data including one or more of geological data, geophysical data, petrophysical data, pressure, volume and temperature (PVT) data, reservoir initial conditions, fluid-contact data, reference point, capillary pressure, relative permeability and well data including one or more of a proposed multilateral well trajectory, an injection well trajectory, pressure response data, production rates to the geological model; andperforming Quality assurance and quality control (QAQC) of the multi-layer transient model with reference to the reservoir data and the well data.

13. The apparatus of claim 9, determining the location further comprising:executing a first simulation scenario with the at least one multilateral well placed at an initial location;in response to the at least one multilateral well failing to satisfy the target production rate at the initial location,adjusting the initial location and iteratively executing a new first simulation scenario at adjusted locations until the at least one multilateral well satisfies the target production rate; anddetermining that the adjusted location is the location for placing the at least one multilateral well.

14. The apparatus of claim 9, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising:receiving multiple candidate lateral spacings for the at least one multilateral well;performing a simulation scenario for each candidate lateral spacing;calculating the first PI for each candidate lateral spacing; andselecting the lateral spacing from the multiple candidate lateral spacings based on the first PI.

15. The apparatus of claim 14, determining the lateral spacing between the lateral sections of the at least one multilateral well further comprising:prior to calculating the first PI, generating a log-log plot to identify a late radial-flow regime.

16. The apparatus of claim 9, determining the well length for each lateral section further comprising:receiving multiple candidate well lengths for the at least one multilateral well;performing a simulation scenario for each candidate well length;calculating the second PI for each candidate well length; andselecting the well length from the multiple candidate well lengths based on the second PI.

17. A system, comprising:one or more memory modules; andone or more hardware processors communicably coupled to the one or more memory modules, the one or more hardware processors configured to execute instructions stored on the one or more memory modules to perform operations comprising:building a multi-layer transient model representing a reservoir based on a geological model;determining a location at the reservoir for placing at least one multilateral well in at least one first simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces hydrocarbons at a target production rate at the determined location;determining a lateral spacing between lateral sections of the at least one multilateral well and a number of lateral sections based on, at least in part, a first productivity index (PI) in at least one second simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each second simulation scenario;determining a well length for each lateral section of the at least one multilateral well based at least in part on second PI in at least one third simulation scenario executed by the multi-layer transient model, wherein the at least one multilateral well produces the hydrocarbons at the target production rate in each third simulation scenario; anddrilling the at least one multilateral well in the reservoir having the determined lateral spacing, the determined number of lateral sections, and the determined well length at the determined location.

18. The system of claim 17, the operations further comprising determining a spacing between the at least one multilateral well and an injection well based on a pressure response and a water cut response at the at least one multilateral well.

19. The system of claim 18, the operations further comprising:receiving multiple candidate spacings between the at least one multilateral well and the injection well;performing a sensitivity analysis for each candidate spacing to obtain an injection pressure response and a water cut response at the at least one multilateral well; andselecting the spacing from the multiple candidate spacings based on the injection pressure response and the water cut response.

20. The system of claim 17, determining the location further comprising:executing a first simulation scenario with the at least one multilateral well placed at an initial location;in response to the at least one multilateral well failing to satisfy the target production rate at the initial location,adjusting the initial location and iteratively executing a new first simulation scenario at adjusted locations until the at least one multilateral well satisfies the target production rate; anddetermining that the adjusted location is the location for placing the at least one multilateral well.

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