The present application relates generally to the field of hydrocarbon exploration, development and production. Specifically, the disclosure relates to a methodology for design and operations of field-wide and multi-well enhanced oil recovery (EOR) of unconventional hydrocarbon assets.
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Hydrocarbon production from tight-oil bearing rocks (e.g., unconventional resources) is almost exclusively via primary depletion, which may leave approximately 90% of the oil in place behind. Enhanced oil recovery (EOR) represents a leading set of technologies to improve oil recovery from unconventional resources. In particular, fluid injection, such as nitrogen injection for reservoir pressure maintenance or carbon dioxide injection for miscible flooding for EOR, may be used. See U.S. Pat. No. 8,984,857, incorporated by reference herein in its entirety. See also US Patent Application Publication No. 20170136401 A1; US Patent Application Publication No. 20170138222 A1; US Patent Application Publication No. 20190322921 A1, each of which are incorporated by reference herein in their entirety.
In one or some embodiments, a computer-implemented method for enhanced oil recovery (EOR) for a plurality of wells in one or more intervals is disclosed. The method includes: accessing an interwell connectivity model comprising interwell connectivity metrics indicative of fluid interconnectivity amongst at least pairs of wells in the plurality of wells, the interwell connectivity model including controllable one or more inputs for inputting gas into a reservoir and one or more outputs related to EOR; and controlling, based on the interwell connectivity model, the one or more inputs for EOR.
In one or some embodiments, a method for hydrocarbon extraction is disclosed. The method includes: accessing an interwell connectivity model that is indicative of fluid connectivity of a plurality of wells; determining, based on the interwell connectivity model, one or more aspects of one or both of control or configuration of the plurality of wells; and using the one or more aspects of one or both of control or configuration of the plurality of wells for hydrocarbon management of a reservoir.
The present application is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of exemplary implementations, in which like reference numerals represent similar parts throughout the several views of the drawings. In this regard, the appended drawings illustrate only exemplary implementations and are therefore not to be considered limiting of scope, for the disclosure may admit to other equally effective embodiments and applications.
The methods, devices, systems, and other features discussed below may be embodied in a number of different forms. Not all of the depicted components may be required, however, and some implementations may include additional, different, or fewer components from those expressly described in this disclosure. Variations in the arrangement and type of the components may be made without departing from the spirit or scope of the claims as set forth herein. Further, variations in the processes described, including the addition, deletion, or rearranging and order of logical operations, may be made without departing from the spirit or scope of the claims as set forth herein.
It is to be understood that the present disclosure is not limited to particular devices or methods, which may, of course, vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting. As used herein, the singular forms “a,” “an,” and “the” include singular and plural referents unless the content clearly dictates otherwise. Furthermore, the words “can” and “may” are used throughout this application in a permissive sense (i.e., having the potential to, being able to), not in a mandatory sense (i.e., must). The term “include,” and derivations thereof, mean “including, but not limited to.” The term “coupled” means directly or indirectly connected. The word “exemplary” is used herein to mean “serving as an example, instance, or illustration.” Any aspect described herein as “exemplary” is not necessarily to be construed as preferred or advantageous over other aspects. The term “uniform” means substantially equal for each sub-element, within about ±10% variation.
The term “seismic data” as used herein broadly means any data received and/or recorded as part of the seismic surveying and interpretation process, including displacement, velocity and/or acceleration, pressure and/or rotation, wave reflection, and/or refraction data. “Seismic data” is also intended to include any data (e.g., seismic image, migration image, reverse-time migration image, pre-stack image, partially-stack image, full-stack image, post-stack image or seismic attribute image) or interpretation quantities, including geophysical properties such as one or more of: elastic properties (e.g., P and/or S wave velocity, P-Impedance, S-Impedance, density, attenuation, anisotropy and the like); and porosity, permeability or the like, that the ordinarily skilled artisan at the time of this disclosure will recognize may be inferred or otherwise derived from such data received and/or recorded as part of the seismic surveying and interpretation process. Thus, this disclosure may at times refer to “seismic data and/or data derived therefrom,” or equivalently simply to “seismic data.” Both terms are intended to include both measured/recorded seismic data and such derived data, unless the context clearly indicates that only one or the other is intended. “Seismic data” may also include data derived from traditional seismic (e.g., acoustic) data sets in conjunction with other geophysical data, including, for example, gravity plus seismic; gravity plus electromagnetic plus seismic data, etc. For example, joint-inversion utilizes multiple geophysical data types.
The term “geophysical data” as used herein broadly includes seismic data, as well as other data obtained from non-seismic geophysical methods such as electrical resistivity. In this regard, examples of geophysical data include, but are not limited to, seismic data, gravity surveys, magnetic data, electromagnetic data, well logs, image logs, radar data, or temperature data.
The term “geological features” (interchangeably termed geo-features) as used herein broadly includes attributes associated with a subsurface, such as any one, any combination, or all of: subsurface geological structures (e.g., channels, volcanos, salt bodies, geological bodies, geological layers, etc.); boundaries between subsurface geological structures (e.g., a boundary between geological layers or formations, etc.); or structure details about a subsurface formation (e.g., subsurface horizons, subsurface faults, mineral deposits, bright spots, salt welds, distributions or proportions of geological features (e.g., lithotype proportions, facies relationships, distribution of petrophysical properties within a defined depositional facies), etc.). In this regard, geological features may include one or more subsurface features, such as subsurface fluid features, that may be hydrocarbon indicators (e.g., Direct Hydrocarbon Indicator (DHI)). Examples of geological features include, without limitation salt, fault, channel, environment of deposition (EoD), facies, carbonate, rock types (e.g., sand and shale), horizon, stratigraphy, or geological time, and are disclosed in US Patent Application Publication No. 2010/0186950 A1, incorporated by reference herein in its entirety.
The terms “velocity model,” “density model,” “physical property model,” or other similar terms as used herein refer to a numerical representation of parameters for subsurface regions. Generally, the numerical representation includes an array of numbers, typically a 2-D or 3-D array, where each number, which may be called a “model parameter,” is a value of velocity, density, or another physical property in a cell, where a subsurface region has been conceptually divided into discrete cells for computational purposes. For example, the spatial distribution of velocity may be modeled using constant-velocity units (layers) through which ray paths obeying Snell's law can be traced. A 3-D geologic model (particularly a model represented in image form) may be represented in volume elements (voxels), in a similar way that a photograph (or 2-D geologic model) may be represented by picture elements (pixels). Such numerical representations may be shape-based or functional forms in addition to, or in lieu of, cell-based numerical representations.
The term “subsurface model” as used herein refer to a numerical, spatial representation of a specified region or properties in the subsurface.
The term “geologic model” as used herein refer to a subsurface model that is aligned with specified geological feature such as faults and specified horizons.
The term “reservoir model” as used herein refer to a geologic model where a plurality of locations have assigned properties including any one, any combination, or all of rock type, EoD, subtypes of EoD (sub-EoD), porosity, clay volume, permeability, fluid saturations, etc.
For the purpose of the present disclosure, subsurface model, geologic model, and reservoir model are used interchangeably unless denoted otherwise.
Stratigraphic model is a spatial representation of the sequences of sediment, formations and rocks (rock types) in the subsurface. Stratigraphic model may also describe the depositional time or age of formations.
Structural model or framework results from structural analysis of reservoir or geobody based on the interpretation of 2D or 3D seismic images. For examples, the reservoir framework comprises horizons, faults and surfaces inferred from seismic at a reservoir section.
As used herein, “hydrocarbon management” or “managing hydrocarbons” includes any one, any combination, or all of the following: hydrocarbon extraction; hydrocarbon production, (e.g., drilling a well and prospecting for, and/or producing, hydrocarbons using the well; and/or, causing a well to be drilled, e.g., to prospect for hydrocarbons; and/or hydrocarbon injection); hydrocarbon exploration; identifying potential hydrocarbon-bearing formations; characterizing hydrocarbon-bearing formations; identifying well locations; determining well injection rates; determining well extraction rates; identifying reservoir connectivity; drilling and/or construction of wells (including drilling the wells or performing hydraulic fracturing); configuring the well site (including selection of the mechanical hardware, such as the compressor(s), the piping, etc. in support of injecting gas to the well(s) or extracting hydrocarbon from the wells); acquiring, disposing of, and/or abandoning hydrocarbon resources; reviewing prior hydrocarbon management decisions; and any other hydrocarbon-related acts or activities, such activities typically taking place with respect to a subsurface formation. The aforementioned broadly include not only the acts themselves (e.g., extraction, production, drilling a well, etc.), but also or instead the direction and/or causation of such acts (e.g., causing hydrocarbons to be extracted, causing hydrocarbons to be produced, causing a well to be drilled, causing the prospecting of hydrocarbons, etc.). Hydrocarbon management may include reservoir surveillance and/or geophysical optimization. For example, reservoir surveillance data may include, well production rates (how much water, oil, or gas is extracted over time), well injection rates (how much water or CO2 is injected over time), well pressure history, and time-lapse geophysical data. As another example, geophysical optimization may include a variety of methods geared to find an optimum model (and/or a series of models which orbit the optimum model) that is consistent with observed/measured geophysical data and geologic experience, process, and/or observation.
As used herein, “obtaining” data generally refers to any method or combination of methods of acquiring, collecting, or accessing data, including, for example, directly measuring or sensing a physical property, receiving transmitted data, selecting data from a group of physical sensors, identifying data in a data record, and retrieving data from one or more data libraries.
As used herein, terms such as “continual” and “continuous” generally refer to processes which occur repeatedly over time independent of an external trigger to instigate subsequent repetitions. In some instances, continual processes may repeat in real time, having minimal periods of inactivity between repetitions. In some instances, periods of inactivity may be inherent in the continual process.
If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted for the purposes of understanding this disclosure.
As discussed in the background, EOR techniques, such as fluid injection, may be difficult to predict due to complex geomechanical processes. In particular, reservoir properties tend to be complex, and may be pressure dependent and/or hysteretic in nature. For example, fluid injected in one or many unconventional wells tends to migrate along hydraulic fractures of the injectors(s) and connect with the fractures of the neighboring wells. In this regard, special capabilities may be used to design an integrated system for improved or optimal hydrocarbon recovery while respecting operational and environmental constraints.
For example, EOR techniques may comprise using gas (e.g., one or both of gas lift or gas injection into the subsurface (e.g., into the reservoir)). Gas may be used to modify the pressure at various parts of the system, such as one or both of within a well (e.g., by using gas lift and/or by modifying the bottomhole pressure through gas injection into the reservoir) or within the subsurface (e.g., at one or more parts of the reservoir within the subsurface). By modifying the pressure (e.g., changing the pressure gradient from the reservoir to one or more bottomholes and/or from the bottomhole to the wellhead), hydrocarbons may be extracted from the reservoir.
In order to perform EOR, one or more models may be used. As one example, reservoir simulation model may be used, such as illustrated in US Patent Application Publication No. 2011/0087471 A1, incorporated by reference herein in its entirety. The reservoir simulation model may be used to generate values for some or all of the potential variables in the subsurface, such as subsurface qualities (e.g., porosity, permeability, etc.) and the effect of injection (e.g., pressure at any point in the subsurface), However, performing a reservoir simulation may necessitate a very high computational cost. As another example, a machine learning (ML) model may be used, such as illustrated in US Patent Application Publication No. 2020/0183047 A1, incorporated by reference herein in its entirety. Again, using an ML model may necessitate a high computational cost.
Thus, in one or some embodiments, a system may comprise an analytical model that is tailored to correlating one or more inputs for EOR with one or more outputs. As one example, any one, any combination, or all of the inputs for EOR, such as one or more aspects related to gas injection (e.g., amount of injected gas, type of injected gas, rate of injected gas, etc.) correlated to any one, any combination, or all of the outputs of EOR, including one or more aspects related to hydrocarbon production (e.g., production rates) and/or one or more aspects associated with the reservoir (e.g., reservoir pressure). As discussed in more detail below, an interwell connectivity metric may be used to correlate the inputs related to gas injection with the outputs related to hydrocarbon production and/or reservoir pressure.
In particular, the disclosed analytical model based on interwell connectivity (interchangeably termed the interwell connectivity model) may be significantly faster (e.g., using the interwell connectivity model may determine pressure in the subsurface in a few hours) than a typical reservoir simulation-based approach (which may take weeks to obtain a history match and to generate a prediction). Thus, in one embodiment, the analytical model is based on well-to-well communication (e.g., the interwell connectivity metric indicative of fluid communication between two or more wells) observed from an EOR field trial, and may therefore be representative of other tight-oil bearing plays/intervals.
In one or some embodiments, the interwell connectivity model may be used to control the one or more inputs for EOR. Merely by way of example, the interwell connectivity model may be used to determine pressure in at least a part of the subsurface, such as in a hydrocarbon reservoir in the subsurface. In particular, the interwell connectivity model may be used to determine the pressure (e.g., the average pressure) in the reservoir based on one or both of an amount of gas injected into the reservoir or a time period of injecting the gas into the reservoir. Alternatively, the interwell connectivity model may be used to determine the inputs needed in order to generate a desired output. For example, the interwell connectivity model may be used to determine one or more aspects of the gas injected (e.g., the amount, the timing, and/or the type) in order to achieve a desired amount of hydrocarbon production and/or a desired amount of pressure in the subsurface (e.g., a desired average pressure in the reservoir). As such, the interwell connectivity model may be used in order to control the inputs (e.g., the gas injected) in order to generate a desired and/or pre-determined pressure profile in one or more parts of the subsurface (e.g., in the reservoir and/or at the one or more bottomholes) in order to perform hydrocarbon extraction.
In this way, various types of EOR may be performed with the effects of the EOR being determined by the interwell connectivity model. For example, one type of EOR is huff and puff, in which during the huff stage, gas is injected via one or more injector wells into the subsurface and thereafter during the puff stage, gas is no longer injected via one or more injector wells into the subsurface. As an analogy, huff and puff is akin to, during the huff stage, blowing air into a balloon and during the puff stage, releasing the air from the balloon. When blowing air into the balloon, the amount of pressure in the balloon increases. Likewise, when injecting gas via the one or more injector wells, pressure increases in the subsurface. In practice, the interwell connectivity model may be used to determine the pressure (such as the average pressure) in the subsurface (such as in the reservoir). Similarly, when releasing air from the balloon, the amount of pressure changes or lowers. Likewise, during the puff, pressure changes in the subsurface, with the interwell connectivity model being used to determine the pressure changes. In one or some embodiments, the interwell connectivity metric may be situationally dependent (e.g., whether building up pressure through huffing or drawing down pressure through puffing) mirroring the pressure dependent and/or hysteretic nature of the subsurface, as discussed further below. In this way, the huff and puff stages may result in pressure changes in the subsurface, with the interwell connectivity model being used to determine the resultant changes in hydrocarbon production rates in one or both of the huff stage or the puff stage.
Separate from being used to determine changes (e.g., production and/or pressure changes) due to gas injection into the subsurface, the interwell connectivity model may be used to determine changes, such as pressure changes and/or production rate changes, when performing gas lift. As discussed in more detail below, gas lift may modify the change in pressure from the bottomhole to the wellhead. In this way, the interwell connectivity model may be used to determine a pressure differential between the reservoir to one or more bottomholes, and may be used in combination with the gas lift (which determines the pressure differential between the one or more bottomholes and the wellheads) in order to provide a holistic approach to pressure (from reservoir to wellhead) in order to extract the hydrocarbons from the reservoir to the wellhead.
Alternatively, or in addition, the interwell connectivity model may be paired with an improvement model or an optimization model in order to control one or more stages of hydrocarbon extraction, such as any one, any combination, or all of: the drilling and construction stage; the primary depletion stage; or the EOR stage (e.g., injecting gas into the tubing as part of huff and puff and/or injecting gas into the annulus as part of artificial lift). More particularly, the interwell connectivity metric may be situationally dependent (e.g., whether building up or drawing down) mirroring the pressure dependent and/or hysteretic nature of the subsurface, as discussed further below.
Thus, in one example, such a system may include any one, any combination, or all of the following components: (1) an analytical model for subsurface response (e.g., the interwell connectivity model); (2) estimating model uncertainty and model tuning for enhancing model predictive capability when new data is available (e.g., updating the model based on data received in a previous stage in order to improve the model for use in subsequent stages); and (3) an improved or optimal design and operational mechanism (e.g., an optimization model for use in selecting one or more parameters in any one, any combination, or all of: the drilling and construction stage; the primary depletion stage; or the EOR stage). In one embodiment, the analytical model, the estimating model uncertainty and model tuning, and the optimization model may comprise separate models. Alternatively, two or all of the analytical model, the estimating model uncertainty and model tuning, and the optimization model may reside within a single model.
Thus, in one or some embodiments, an analytical model (e.g., the interwell connectivity model) is used that is configured to predict and/or forecast one or more metrics related to EOR, such as the subsurface response and/or the use of resources (such as injectant leakage and/or sequestration), to one or multiple stimuli including fluid injection for interconnected well configuration (e.g., one or both of injection well(s) and producing wells). As discussed in more detail below, the analytical model may use any one, any combination, or all of the following in order to determine the EOR metrics: well-to-well connectivity (e.g., an interwell connectivity metric); a number of wells; or configuration of neighboring wells. Example EOR metrics include any one, any combination, or all of: bottomhole pressure (BHP) of one or both of the injector well(s) and offset well(s) during EOR processes; reservoir pressure; amount of injectant leaking out of area of interest; oil production rates; or the like. In turn, the analytical model may use one or more of the EOR metrics in order to generate one or more additional metrics. For example, the analytical model may use BHP in order to predict one or both of oil recovery (e.g., the total oil recovery from the wells in the one or more intervals) and/or the oil uplift (e.g., an indicator of the incremental oil production increase in the one or more intervals) and/or pressure in one or more parts of the subsurface.
Thus, in one or some embodiments, the analytical model, which may be based on interwell connectivity, may be used to predict one or more reservoir properties. Further, various ways are contemplated in order to determine interwell connectivity. In one or some embodiments, interwell connectivity may be generated for a plurality of wells (such as different pairs of wells) and may be indicative of any one, any combination, or all of: physical proximity of the plurality of wells; subsurface indicators (e.g., stress orientation in the subsurface); fluid connectivity (e.g., whether and/or how gas injected into tubing of an injector well travels to an offset well, such as the tubing of the offset well); presence of natural and/or hydraulic fractures connecting wells; and rock properties (e.g., permeability).
As one example, interwell connectivity may be derived or determined based on pressure. In particular, due to complex geomechanical processes, reservoir properties may be pressure dependent and hysteretic in nature. As such, in one or some embodiments, the interwell connectivity may be dependent on pressure. More specifically, the interwell connectivity may be dependent on whether there is a build-up (e.g., increasing pressure) or a draw-down (e.g., decreasing pressure). In this way, the interwell connectivity, as a reflector or indicator of reservoir properties, may be both dependent on pressure and hysteretic in nature. As discussed further below, such a predictive capability may be used in combination with improvement or optimization modeling in one, some, or all of the following: assist in the design and implementation of various aspects of EOR, such as compression/pumping capacity for injection; predict various results (e.g., the amount of injectant leaking to offset wells); and optimize a field implementation of EOR in unconventional reservoirs.
Further, in one or some embodiments, the interwell connectivity model, which may be indicative of the impact of injecting gas on the pressure system on one or more aspects of hydrocarbon extraction, may include use different physics equations depending on one or more aspects of the system. For example, in a first state (e.g., depending on pressure), the gas may be dissolved in the oil in the subsurface, and in a second state (in which the pressure is greater than the bubble point), may not be dissolved in the oil. Each state has an associated set of physics equations to describe the behavior of the gas in the subsurface. In this way, in one or some embodiments, the interwell connectivity model may incorporate the different states and associated equations in determine the effect of injecting gas.
As discussed above, the analytical model may be used in various stages of hydrocarbon extraction, including any one, any combination, or all of the design stage (e.g., drilling and/or construction), primary depletion stage, or gas injection stage (e.g., one or both of gas injected into the tubing as part of huffing or injected into the annulus as part of an artificial lift). In particular, the analytical model may be used in combination with (or as part of) the design and operational mechanism in order to determine improved or optimal EOR in a variety of contexts in hydrocarbon management. As one example, the analytical model may be used as part of an improved or optimal design and operational mechanism that is configured to select improved or optimal option(s) of EOR system design parameter(s). Various types of improved or optimal design and operational mechanisms are contemplated. For example, various models are contemplated as improved or optimal design and operational mechanisms, such as any one, any combination, or all of: design model (which may be used for improvement or optimization for the design stage in determining the drilling and/or construction parameters, such as the number of wells, the placement of wells, the hardware used, etc.); primary depletion model (e.g., which may be used for improvement or optimization for the primary depletion stage in determining various aspects of primary depletion, such as when to end the primary depletion stage); the gas injection model(s) (e.g., one or more models to determine one or both of whether, what, and/or how long to inject gas into the tubing as part of huffing and/or to determine whether, what, and/or how long to inject gas into the annulus as artificial lift). In this regard, the various models, such as the design model, the primary depletion model, and the gas injection model(s) may be used at the various stages of hydrocarbon production. In one or some embodiments, the design model, the primary depletion model, and the gas injection model(s) may comprise separate models. Alternatively, two or more of the design model, the primary depletion model, and the gas injection model(s) may reside within a single model.
In particular, one or more system parameters related to any one, any combination, or all of the design stage, the primary depletion stage, or the gas injection stage may have potential values (such as a range of values) that may be used. The improvement or optimization model may work in combination with the analytical model, due to its predictive nature, to analyze different potential values for the one or more system parameter(s) and to select the values for the one or more system parameter(s), which may in turn be used in the various stages of hydrocarbon extraction. In one or some embodiments, the improvement or optimization model may further include other constraints, such as economic constraints, practical constraints, or the like, in order to identify values for the one or more system parameters. In this way, the design and operational mechanism (which may include the improvement or optimization model and the analytical model) may determine an improved set of values for the one or more system parameters.
As discussed above, the improvement or optimization model may be manifested in a single model for a respective stage (or a respective sub-part of a stage, such as cycle operations model_1 1024, discussed below). For example, a design model may be used for improvement or optimization of parameters in the design stage (e.g., selection of parameters for drilling and construction), a primary depletion model may be used for improvement or optimization of parameters in the primary depletion stage, and one or more gas injection models may be used for improvement or optimization of parameters in the gas injection stage (e.g., one or more models for generating parameters: (i) for huff and puff in the injector well(s) and/or offset wells; and/or (ii) for artificial lift in the injector well(s) and/or the offset wells). Alternatively, the improvement or optimization model may be manifested in a model that spans multiple stages in the hydrocarbon development, such as any two or more of the design stage, the primary depletion stage, or the gas injection stage.
The respective model may be used in combination with the analytical model to analyze different sets of potential values for “N” parameters (e.g., first set of potential values include values for the “N” EOR system design parameters; second set of potential values include values for the “N” EOR system design parameters; etc.). Depending on the respective parameter, the potential values may be discrete (e.g., the number of wells, which may comprise integer numbers); continuous (e.g., temperature, pressure, flow rates, etc. may have associated ranges of potential values); or categorical (e.g., a variable is assigned a value that is not a number). The analytical model, using the values for a respective set of potential values, may predict one or more metrics, such as any one, any combination, or all of the following EOR metrics: bottomhole pressure; amount of injectant leaking out of area of interest; amount of injectant being sequestered in the area of interest; oil production rates; or the like. Based on the one or more metrics, the improved or optimal design and operational mechanism may select an improved (or optimal) set of potential values of the design parameters. As one example, the improved or optimal design and operational mechanism may perform a cost-benefit analysis using the one or more EOR metrics generated by the analytical model in order to select one set of the potential values of the EOR system design parameters. As another example, the improved or optimal design and operational mechanism may weight the one or more EOR metrics generated by the analytical model in order to select one set of the potential values of the EOR system design parameters.
In practice, an optimization algorithm may be used in order to select values for one, some, or each of the parameters at issue. Further, in a first step, initial values for the parameters may be selected. In one or some embodiments, an engineer or the like may select the initial values. Alternatively, the initial values may be automatically selected (e.g., the automatically selected initial values may be presented to the engineer for approval). Still alternatively, the initial values may be selected based on a combination of manual and automatic selections.
In a second step, an algorithm, such as a genetic algorithm or other type of evolutionary algorithm, may input the initial values and be used in order to evaluate and select one or more “best’ solutions. Thus, the algorithm may provide a way in which to consider various physical inputs in determining “best” potential solution(s). Merely by way of example, contemplated algorithms include differential evolution (or other type of evolutionary computation), simulated annealing algorithm, or particle swarm optimization. The algorithm may iterate through various solutions, with the first iteration using the initial values determined in the first step. Thereafter, the algorithm may modify the values of the parameters to identify the defined “best” solution (or a set of “best” solutions). By way of example, the algorithm may randomly populate the space around the initial guesses and evaluate the model for each of the specific combination of inputs, with each iteration biasing more toward an area of the space where the answer tends more to the defined “best” solution.
In one or some embodiments, the “best” solution may be defined in one of several ways, including based on one or more factors. Example factors include, but are not limited to, any one, any combination, or all of: production metrics (e.g., BHP, oil recovery, oil uplift); costs (e.g., material costs (e.g., fluid costs), equipment costs (e.g., pumps or the like); worker costs (e.g., amount of time and/or frequency of monitoring or controlling equipment); or efficiency of the process (e.g., utilization, such as the incremental number barrels of oil produced per volume of injected gas). Other factors may include largest present value (which may be used where a project has unlimited capital) or a largest present value ratio (or the rate or return).
In addition, in one or some embodiments, the factors may be weighted in order to select what is defined as the “best” potential solutions. As one example, oil uplift and material costs may be weighted in order to select the “best” solutions. As another example, oil uplift, material costs, and worker costs may be weighted in order to select the “best” solutions. The engineer may then be presented with the “best” potential solution or the set of “best” potential solutions in order for the engineer to select one solution for implementation. The presentation of the “best” potential solution(s) may further include information on the associated factors. Merely by way of example, a set of potential solutions may be presented to the engineer. Though the algorithm did not factor worker costs in selecting the set of “best” potential solutions, the engineer may be presented with the set of “best” potential solutions along with other information, such as associated worker costs. For example, two potential solutions (selected based on oil uplift) may be presented to the engineer, with a higher-ranked solution requiring more work from workers (e.g., more frequent trips to the field to monitor the wells) or more operational changes (e.g., more frequent operational changes, potentially increasing the likelihood of equipment breakdown) versus a lower-ranked solution requiring less work from workers or fewer operational changes. In this regard, in one or some embodiments, the engineer may be presented with an array of potential solutions (selected by the algorithm based on factor(s)), and may select the optimal solution (selected by the engineer based on the factor(s) used by the algorithm and/or other factors not used by the algorithm). In the example presented above, in viewing the presented higher-ranked and lower-ranked solutions, the engineer may select the lower-ranked solution due to incremental oil uplift in the higher-ranked solution not justifying the additional work from the workers in the higher-ranked solution. In this way, the algorithm may present a set of “best” potential solutions that may assist engineers in making operational decisions.
As discussed above, selection of one or more design parameters using the analytical model and the optimization model are contemplated in one or more stages. By way of example, during the design stage, values for any one, any combination, or all of the following may be selected: (1) the number of wells for drilling; (2) the spacing between the wells drilled; (3) the well design parameters (e.g., vertical portion of the well, horizontal portion of the well; etc.); (4) the specifics of completions (e.g., the design of the hydraulic fractures); (5) well surveys (e.g., well surveys may define the trajectory of a well in 3 dimensions, and may comprise an array of numbers with 3 columns for x, y and z coordinates; by way of numerical example, the well survey may indicate that the well is vertical at a given co-ordinate on the map (x, y) indicate from z=0 to z=8000 ft, then the well turns horizontal over z=8000 ft to z=9000 ft, and then it is drilled horizontally over 10,000 ft, so it might say at z=9000 ft, x changes from 0 to 10,000 ft); (6) the hardware for the field (e.g., the width of the tubing; the width of the annulus; the size and number of compressor(s); the compression/pumping capacity of the compressor(s) for injection of gas into the tubing and/or the annulus); or (7) injected gas volume requirements. During the primary depletion stage, values for one or both of the following may be selected: (1) when to end the primary depletion stage (and to enter the huffing and puffing stage, such as when to begin cycle 1 as depicted in
Generally speaking, during the gas injection stage, values relating to gas injection via tubing (e.g., huffing) and/or values relating to gas injection via the annulus (e.g., artificial lift) may be selected. More specifically, with regard to huff and puff in which gas is injected via tubing of injector wells, values may be selected for any one, any combination, or all of the following: (A) values selected for overall operation of huff and puff across multiple cycles; or (B) values selected for operation within a specific huff and puff cycle including values for operation of the injector well(s) and/or values for operation of the offset well(s).
With regard to (A), which is overall operation of huff and puff across multiple cycles, values may be selected for any one, any combination, or all of: (i) the number of cycles of huffing-and-puffing (such as three as illustrated in
With regard to (B) as to operation of the injector wells, values may be selected for any one, any combination, or all of: (i) the specifics of the huffing in a respective cycle (e.g., the number of wells to select as injector wells; the specific wells to select as injector well(s) for injection of the gas into the tubing of a respective well selected as an injector; the sequence of which wells to select for injection); (ii) the injection rate of the gas into the tubing and/or the injection rate of the gas into the annulus; (iii) the injection volume of the gas into the tubing (e.g., the entire volume of gas injected over a single huffing cycle) and/or the injection volume of the gas into the annulus; (iv) the rate of injection over time during huffing and/or during artificial lift (e.g., step-change from zero rate of injection to the predetermined maximum rate of injection during huffing; ramping upward at a predetermined rate of change from zero rate of injection to the predetermined maximum rate of injection during huffing; other combinations of time and rate to modify rate of injection); (v) the duration of injection during huffing and/or during artificial lift; (vi) the sequence of which injector wells to inject gas in (e.g., injection starting time and/or injection duration); (vii) the sequence of which injector wells are artificially lifted; (viii) injection rates during huffing and/or during artificial lift; (ix) injection/producing configuration (e.g., average pressure of the area in which EOR occurs); (x) the type of gas for injection during huffing and/or during artificial lift; (xi) choke settings during artificial lift; (xii) whether to artificially lift an injector well (e.g., which wells to flow only naturally and which wells to artificially lift), and if so, the rate and duration of artificial lift; (xiii) whether to use the same type of gas for injection into the tubing (e.g., huff) and for injection into the annulus (e.g., artificial lift); or (xiv) if the same type of gas is used for injecting gas into the tubing (e.g., huff) and for artificial lift, determining how to split the gas between the two processes to maximize profitability of the operation.
With regard to (B) as to operation of the offset wells, values may be selected for any one, any combination, or all of: (i) which offset wells to cap and which not to cap (so that the offset well can continue producing); (ii) for producing offset well(s), determine whether/when to artificially lift (and for how long) or to flow naturally (e.g., based on injecting gas in an injector well, determine whether and/or when to artificially lift relative to the huffing of injecting gas in the injector well); or (iii) timing for artificial lift in offset well.
In particular, for the offset wells, the model(s) may determine (i) the offset wells selected for plugging during huffing; (ii) for the offset wells selected for plugging during huffing, how long to plug those offset wells (e.g., coextensive with the huffing; not coextensive with the huffing; same length of time to plug as the length of time for huffing into the injector wells; different length of time to plug than the length of time for huffing into the injector wells); (iii) which offset wells only to flow naturally versus using artificial lift; (iv) for offset wells with artificial lift, the injection volume of the gas into the annulus; (v) the rate of injection over time during artificial lift (e.g., step-change from zero rate of injection to the predetermined maximum rate of injection during huffing; ramping upward at a predetermined rate of change from zero rate of injection to the predetermined maximum rate of injection during huffing; other combinations of time and rate to modify rate of injection); (vi) the rate and/or the duration of injection during artificial lift; (vii) the sequence of which offset wells are artificially lifted; (viii) injection rates during artificial lift; (ix) injection/producing configuration (e.g., average pressure of the area in which EOR occurs); (x) the type of gas for injection during artificial lift; or (xi) choke settings during artificial lift.
Thus, the design and operational mechanism may be configured to support decisions in one or more stages of hydrocarbon extraction even in the presence of subsurface (both geologic and fluid system) and market uncertainties. Such an integrated system may improve or optimize reservoir/field management under any desirable operational and environmental constraints.
Further, given additional information, such as additional data in the course of performing EOR in the field, the analytical model may be updated. For example, responsive to receiving additional diagnostic data, the analytical model may be updated, such as illustrated in
Further, the present methodology is scalable, in terms of number of wells and/or geometric configurations of wells. As such, new wells may be added, or old wells may be removed. In addition, well-to-well communication may be tuned based on distance, number of neighbors, and level of communication as a function of stress direction in the subsurface. As such, the methodology may be applied to a variety of contexts, whether on a pad-scale or on a commercial-scale. In this way, the methodology may be applied to a large number of wells (e.g., greater than wells) across a single interval (or other zone of interest) or across multiple reservoir intervals (such as one or more intervals) and thus may assist in the design of a pilot-scale project and/or a full-field scale application.
Thus, the methodology may be configured to predict one or more EOR metrics within the field, such as within the one or more injector well(s) and/or within the one or more offset wells. Merely by way of example, the methodology may predict how bottomhole pressure BHP is expected to build in an injector well as a function of any one, any combination, or all of: well-to-well connectivity (e.g., an interwell connectivity metric); a number of wells; or configuration of neighboring wells. Further, the methodology may predict the metric in one or more offset wells. For example, the methodology may predict how BHP may build in offset wells as a function of injection from neighboring wells. The methodology may further predict one or more metrics outside of the field (e.g., predicting what fraction of injectant will leak outside the well pattern).
In addition, the methodology may be configured to predict the complex interactions between the one or more injector well(s) and the one or more offset wells. For example, the methodology may determine how much compression (or how much injection rate) may be needed to overwhelm well-to-well communication (e.g., to overwhelm the loss of fluids to other wells) before the pressure of the injector well(s) and the offset wells may increase. Thus, in one or some embodiments, the methodology may determine the compression necessary to overwhelm well-to-well communication as a function of any one, any combination, or all of: pressure; fluid properties; or one or more aspects of the wells (e.g., layout or geometry) of the wells). In this regard, the compression necessary may be a function of aspects that are controllable (e.g., one or both of the pressure applied, the fluids selected, etc.) and other aspects that may not be controllable (e.g., in an existing field of wells, the well layout, pattern, or spacing).
In this regard, the methodology may generally assist in hydrocarbon management. For example, the analytical model, as part of the methodology, may assist in determining any one, any combination, or all of: a duration of injection (such as the number of injection days) for a given well configuration, communication and compression/pumping in order to reach a target pressure during injection; which wells to pick as injectors; how to split the injected fluids among many wells to maximize a pressure metric (such as average pressure) over an area of interest (e.g., over one or more intervals); and selection of strategies to contain the transport of injected fluid on injection rates, pressure builds and leak outside the area of interest (e.g., plug off one or more leak zones, such as by intentionally injecting cement or polymers to plug off the one or more leak zones; conformance control in terms of attempting to direct the fluid in a certain direction: injecting water which is immiscible thereby creating a larger resistance for transport). Merely as one example, the optimization algorithm may analyze whether and how to split injected fluids amongst multiple injector wells. In one or some embodiments, the optimization algorithm may analyze one or more metrics, such as a pressure metric. In particular, the optimization algorithm analyzes the split of injected fluids in order to a maximum pressure needed in the one or more injector wells. In response, the determined maximum pressure may then be used in order to select the hardware, such as the compressor, needed to generate such maximum pressure and the costs associated with purchasing such hardware. In this way, the optimization algorithm may assist in determining the various operational conditions warranted (e.g., the maximum pressure) and in selecting the appropriate hardware capable of performing under the operational conditions (e.g., purchasing the smallest compressor that still is capable of generating the maximum pressure). In this regard, the methodology may be used in a predictive mode and/or in an improvement/optimization mode in the field given certain constraints.
Referring to the figures,
As discussed in more detail below, the analytical model is configured to predict one or more EOR subsurface responses, such as bottomhole pressure (P1) of the injector well and bottomhole pressure (P2, P3, etc.) in one or more offset wells during EOR processes.
The wells depicted in
In this regard, production data for these wells are available, and may therefore be used by the analytical model in order to predict the effect in the subsurface when liquid/gas are injected, such as in gas injection through tubing of a respective injector well. In this regard, the analytical model, using the available production data and generally accepted geomechanical principles) may predict, for a given well at a given pressure, the expectation as to the flow of the liquid/gas from an injector well to one or more offset wells (e.g., how the connectivity, such as fluid connectivity, between the wells may change as a function of pressure). Specifically, the analytical model may consider any one, some or each of the following three different domains: (1) the geomechanics of the system (e.g., how the fractures from adjacent/different wells may communicate with each other); (2) the physical location of the wells; and (3) the chemistry or fluid mechanics involved (e.g., the quantity of fluid/gas to be added to build sufficient pressure and the effectiveness to build pressure in order to create an enhanced/upload for a fluid flow back from the well).
In one or some embodiments, the analytical model may be based on subdividing the interval into discrete units, and generating an indicator of the fluid interconnectivity within the discrete unit. In a specific embodiment, the interval may be subdivided by wells, such as pairs of wells. In turn, an interwell connectivity metric may be assigned to respective pairs of wells indicative of the fluid interconnectivity amongst the respective pair of wells. It is noted that the interwell connectivity metric need not be limited to only two wells in a pair. Greater than two wells may be assigned an interwell connectivity metric. Thus, the interwell connectivity metric may be an indicator of physical proximity of the plurality of wells and/or subsurface indicators (e.g., stress orientation in the subsurface). For example, a given injector well and its immediate physically adjacent neighbor well may have a higher interwell connectivity metric than a secondary well (or even tertiary wells) that is not the given injector well's immediate neighbor (e.g., once removed or twice removed from the given injector well). Though, the secondary well or the tertiary well may still have some connectivity with the given injector well (as indicated by the interwell connectivity metric). However, physical proximity is merely one aspect accounted for with regard to the interwell connectivity metric. Rather, the interwell connectivity metric may account for other more complex subsurface features, such as stress orientation. In this way, the interwell connectivity metric may depend on physical proximity of the wells as well as direction of stressors in the subsurface reservoir.
Referring back to
As such, the analytical model may assign the interwell connectivity metrics to the following pairs: well #16:well #15 (identified as F16,15); well #16:well #29 (identified as F16,29); and well #16:well #5 (identified as F16,5). In this way, the analytical model may be tailored to any interval with any layout of wells.
In this way, the analytical model 200 may be configured to predict one or more aspects of the reservoir, such as reservoir pressure and/or other subsurface response factors. In particular, the analytical model 200 may predict one or more subsurface responses (e.g., the bottomhole pressure in each well) respond to one or more stimuli such as fluid injection, duration of the injection operation, the sequence of the injection, and/or average pressure of the area in which EOR occurs. The analytical model 200 may incorporate anisotropic stress condition in the subsurface and resulting anisotropy in gas transport to provide a geologically representative prediction of the pressure build. Further, as discussed above, the analytical model 200 may consider a wide range of injected fluids (as illustrated by the input for one or more types of fluids), including any one, any combination, or all of: separator gas; hydrocarbon gas; hydrocarbon liquid; water; CO2; surfactant solutions; or foams.
In one or some embodiments, the analytical model 200 may be manifested in one of several ways. In one way, the analytical model may comprise one or more equations, such as the following:
with V1, V2, and V3 comprising control volumes represent parameters whose values that may be estimated based on primary depletion. As discussed below, additional or different terms may be used in the equations comprising the model. For example, it is noted that the system may further consider variable(s) directed to the physics (e.g., δ). In such an instance, Equations (1)-(3) may be updated as follows:
As discussed further below, δ may be determined by machine learning. Merely by way of example, data may be used in order to update the analytical model (see model calibration 1010, 1012, 1014, 1016), as discussed further below.
In this way, the analytical model may comprise a series of differential equations that represent mass balance on a control volume probed by injected fluid around each well, such as schematically illustrated in
As discussed above, the analytical model 200, for the layout illustrated in
Further, the analytical model 200 may be updated periodically, such as based on receipt of diagnostic data, as discussed above. See
Referring back to
As discussed above, the analytical model may be used in a variety of contexts, including in designing a pilot-scale project or a full-field scale application. In this regard, the analytical model may be used in a predictive mode or in an improvement/optimization mode using design and operational mechanism 250 in order to determine, given certain constraints, the parameters to select. This is illustrated, for example, in
In particular, in a first step, values (such as a range of values) of input parameters may be determined, such as reflected in potential system design parameter(s) values 260. As discussed above, in the gas injection stage, input parameters may include: the choice of wells (including which well(s) for injection and/or which wells not for injection); how much fluid to inject; sequence of fluid injection (e.g., in the example illustrated in
Practically speaking, there may be physical constraints and economic constraints in the values. For example, physical constraints may be imposed by a real system. In particular, the real system may only have a given amount of gas available and/or a certain amount of pressure available without a resulting safety issue. In this regard, the physical constraints may dictate bounds as to potential values for the input parameters. As another example, economic constraints may likewise limit the potential values for the input parameters. For example, cost limits may dictate a cap on the amount of spend, with the potential spend varying at different stages (e.g., a budget limit of $1 million until receiving positive feedback, after which the budget limit increases to $10 million in order to purchase additional equipment (e.g., purchasing a larger compressor) or performing additional acts (e.g., injecting in more wells)).
In a second step, various given sets of values for the input parameters (reflected in set(s) of system parameter values for analysis 270) may be analyzed using the analytical model 200 in order to determine improved or optimal values for the input parameters based on pre-defined objectives or metrics. In one or some embodiments, the design and operational mechanism 250 may be configured to handle one, some or each of continuous (such as injection rates in the gas injection stage), discrete (such as number of wells and well configuration in the design stage) or categorical (such as a compressor selected from a set of commercially-available compressors) decisions. The design and operational mechanism 250 may use one or multiple optimization approaches based on the availability of model sensitivity (e.g., adjoint). In one or some embodiments, the design and operational mechanism 250 may include one or more optimization models, which may be manifested in one of several ways, such as in equation form.
where J(P, q, r) is the objective function that represents user-defined physical or economic metric to be optimized. Further, P may comprise the pressure in the subsurface, q may comprise flow rates, r may comprise a discount rate (e.g., assuming that J is indicative of net present value). As discussed in more detail below, when seeking to optimize for an identified metric, the optimization may focus on net present value or another defined value. For example, the object function may include any one, any combination, or all of: the cost of the gas; cost of drilling/completion; cost of treating the gas after its production; or the value of the oil.
For example, the values for the input parameters may be varied in a systematic manner in to identify an improved or a “best solution,” based on the pre-defined objectives or metrics. An initial set of system parameter values for analysis may be selected in one of several ways, such as based on the engineer's judgement. After analysis of the initial set of system parameter values, the design and operational mechanism 250 may systematically alter the values of the system parameters through the design space in order to select, by the design parameter selector 280, an improved or optimal solution for the set of system parameter values. In this way, the design and operational mechanism 250 may iterate to progress to the selected solution.
Referring back to the example illustrated in
Referring back to
In one or some embodiments, using the distance between the wellbores (), width of the fracture conduit (w), porosity of the fracture (ϕ), viscosity of the fluid (μ), and total compressibility of the system (ct), interwell conductivity may be calculated using the hydraulic diffusivity equation:
As discussed above, Eq. (13) may be coded in a Microsoft Excel Spreadsheet or in Python, which may allow engineers to use the tool in a variety of contexts, such as in any one, any combination, or all of: for a wide range of pressures; for various numbers of wells; and for various types of fluid and rock properties. For example, responsive to determining the interwell connectivity (F), the effective width of the fracture conduit (w) may also be estimated from Eq. (13), if all other geometry parameters and fluid properties are known.
As shown in
The methodology may be extended to quantify response times and conductivity between the injector well and the other offset well (e.g., well 3 (130) in
In one or some embodiments, the methodology may be used for fracture characterization. For example, fluid injection may be used as a fracture diagnostics technique to quantify well connectivity as a function of pressure. In one or some embodiments, the fracture diagnostics technique may indicate one or more aspects of the fracture, such as the exact location of the fracture. In turn, the fracture characterization may assist in the design of fracturing/completion on other wells (e.g., other wells in the vicinity) and/or assist in improving/optimizing well spacing and stacking (e.g., vertical and lateral spacing) in the development of unconventional reservoirs. Merely by way of example, the fracture characterization may assist in selecting any one, any combination, or all of the following aspects of fracturing/completion: type of proppant; amount of proppant; number of clusters/stage; stage spacing; amount of fluid used for completion; or type of fluid used for completion. Thus, in practice, the fracture characterization may be used to select or modify one or more aspects of the fracturing/completion of the other wells.
Based on the time lag (Δt) between a change in injection rate at a well (e.g., well 1), and the sensed change in the bottomhole pressure in an offset well (e.g., well 2), the fractures may be characterized at least in part. For example, based on the time lag (Δt), one of more of the fracture diagnostic scenarios may be eliminated. For example, (scenario C in this case) may be eliminated. Injection of gas or fluid in one more wells may be used as a fracture diagnostic technique to eliminate scenarios inconsistent with the interpreted interwell conductivity. Thus, in an instance where the injector well includes fractures and the offset well(s) likewise include fractures, injecting gas into the injector well and sensing the response in the offset well(s) may assist in characterizing the fractures, such as potentially eliminating fracture scenarios, and in turn narrowing the uncertainty in the subsurface.
Further, as discussed above, interwell connectivity may be strongly correlated of pressure whose behavior may be highly hysteretic. In addition, interwell connectivity may be approximately twice as sensitive to pressure compared to lab-derived pressure dependent permeability on intact rocks, which may indicate that the interwell connectivity may account for non-ideal situations (and the potential complexities of fractures in the subsurface) not considered in simulations.
Also, interwell connectivity during injection at high bottomhole pressure may diminish significantly once the wells are depleted. Consequently, wells may be more disconnected at low bottomhole pressure or during depletion compared to high pressure and injection. Thus, in one or some embodiments, the interwell connectivity may be monitored in order to determine when the well is depleted (e.g., as an indicator of well depletion). In this regard, the interwell connectivity may be used when to begin and/or when to end EOR. For example, the analytical model in combination with an improvement or optimization model may determine when to end the primary depletion stage (and begin the gas injection stage) based on the determination when the well(s) are depleted.
Finally, a calibrated model that describes interwell connectivity as a function of pressure may be used to estimate the amount of gas needed to build pressure as a function of injection rate.
The analytical approach thus allows the strength of well-to-well interaction to change as a function of the average bottomhole pressure and whether the pressure increases or decreases. This added versatility makes the analytical approach broadly applicable across well-to-well interactions characterized by multiple flow regimes. In this way, another variable in terms designing operations (e.g., controlling and selecting operations) may comprise whether to build-up or to draw down. Thus, the hysteretic behavior of the system may be used to design EOR operations.
Further, the analytical approach may be significantly faster to implement and run than a hydraulic fracturing simulation based approach, as discussed above. Because of its simplicity, the methodology may be automated. The methodology need not attempt to differentiate between various mechanisms behind the pressure dependence of the interwell conductivity. Rather, the methodology may lump some or all of the geomechanical complexity into one or more terms of Eq. (5), which 2 parameters “a” (a constant) and “b” (in an exponent). Additionally with regard to simplicity, the methodology may be based at least in part (or entirely) on the time lag (Δt) needed for a pressure signal to travel from an injector to an offset well. In this way, the methodology need not depend on the magnitude or percent pressure change in a given time interval.
Moreover, the methodology may be validated on well-to-well communication observed from an EOR field trial. In this manner, the exponential functional form is contemplated to be broadly applicable, though the specific parameters in the methodology (e.g., “a” and “b”) may be tuned for different systems.
As discussed above, the analytical model may be used in a variety of contexts. For example, the analytical model may be used in combination with another model to select parameters to improve or optimize one or more stages of hydrocarbon extraction, such as any one, any combination, or all of: the design stage; the primary depletion stage; or the gas injection stage. Further, it is noted that the stages, including the primary depletion stage and the gas injection stage, may span at least one decade, at least two decades, at least three decades, or more. As such, the efficiencies derived from use of the model(s) may significantly improve extraction of hydrocarbons.
In one or some embodiments, the system may be composed of multiple components, such as any one, any combination, or all of: wells; reservoir(s); surface pipelines; and equipment (e.g., compressor(s)). The analytical model may be configured to model one or more processes, such as the physical process (e.g., the fluid flow) and/or chemical processes (e.g., chemical reactions) of fluids in one, some or each of the system components. In one or some embodiments, the analytical model comprises a single model to model each of the processes, including the physical process and the chemical process. Alternatively, the analytical model comprises separate models to model each of the processes, including a physical process model and a chemical process model.
In one or some embodiments, the design model 930 may include one or more constraints in selecting the optimal values for the design stage, with the constraints including any one, any combination, or all of: practical constraints (e.g., maximum rate of gas that can be delivered by a gas pipeline; contractual obligations to deliver a certain amount of gas to a specific customer; equipment malfunction that might limit injection rates/durations; weather events affecting electric power supply or operability (e.g., the winter storm in Texas in February 2021)); budgetary constraints (e.g., gas price; transportation cost charged by pipeline operators; limits on capital or operating costs set in annual budgets); or best practices/intuition (e.g., recommendation not to make significant changes on a Friday afternoon, as field operators may not be able to respond quickly if a problem arises).
In one or some embodiments, the constraints may be embedded in the math as either equations/inequalities (e.g., the production should be less than a first predetermined number or the budget should not increase beyond a second predetermined number) or rules (e.g., if “X” occurs, then “Y” should be performed). In one or some embodiments, certain constraints, such as the probability of operations issues with equipment malfunction and/or weather issues may be more difficult to predict; therefore, these issues are not included or embodied in the math.
In practice, the design model 930 may input or access configuration options, such as one or more options for different configurations for drilling and construction. Example options include values for different numbers of wells, values for different well spacing, values for different well configurations (e.g., different horizontal depths; different pipeline widths; different fracturing configurations), values for different compressors (e.g., compressors with different pumping capabilities and associated costs), and/or values for different surface piping (e.g., different piping widths). The design model 930, using the reservoir interconnectivity model 932 (which may indicate the response from the subsurface) and the drilling+construction optimization model 934 (which may be constrained in one or more ways as described above), may select a drilling+construction configuration, which may include values for one or more parameters associated with the design stage, including any one, any combination, or all of: the number of wells to drill; the well spacing for the wells drilling; the well configuration; the value for the compressor; and the value for the surface piping.
In practice, the operations model 950 may input configuration options, such as one or more options for different configurations for gas injection, including gas injection into the tubing of wells (e.g., for huffing) and/or gas injection into the annulus (e.g., for artificial lift). Example options include, without limitation, any one, any combination, or all of: the number of cycles of huffing-and-puffing; the length of time of the cycles; which wells to select as injector well(s) for the gas; the injection rate; the injection volume; the duration of injection; the sequence of which injector wells to inject in; the type of gas for injection; for injector well(s) and/or offset wells, whether to artificially lift, and if so, the rate and duration of artificial lift; which offset wells to cap or plug (and when to cap/how long to cap) and which not to cap; or timing for artificial lift in injector well(s) and/or offset well(s).
The operations model 950, using the reservoir interconnectivity model 932 (which may indicate the response from the subsurface) and the operations optimization model 952 (which may be constrained in one or more ways as described above), may select the gas injection configuration, which may include values for one or more parameters associated with the gas injection stage, including the number of wells to drill, the well spacing for the wells drilling, the well configuration, the value for the compressor, and the value for the surface piping.
S(y(x,z),x,z)=0 (14)
v=D(y)+ϵ(x,z) (15)
As mentioned, S may generally not be precisely known. Thus, one may assume that there is a computational model (e.g., mathematical, statistical, machine-learning) that may represent the system S according to the following:
S(y(x,z),x,z)={tilde over (S)}(y(x,z),x,z,θ)+δ(x,z,θ) (16)
θ denotes modeling aspects needed to run the computational models, which may include any one, any combination, or all of: geological geometry; rock properties; fluid properties; one, some or each well location; configuration and geometry; wells relative locations; compression capacity; or well type (e.g., injection producing).
δ denotes model bias or discrepancy (e.g., functional discrepancy or bias correction) due to unknown or mis-modeled physical or chemical aspects of the process. In this regard, δ may account for any one, any combination, or all of physical, thermal, or chemical reactions. As one example, when CO2 is injected, there is a potential for a reaction, such as a thermal reaction. As another example, δ may account for calcification, whereby CO2 may react with water or calcium to form calcium carbonate. Thus, this term may indicate that {tilde over (S)} has systematic imperfections, even under its best tuned parameter θ*. One may assume that reasonable correction to {tilde over (S)} may be learned through δ. Further, δ may be determined or learned algorithmically from the data.
The same argument may apply for observation model D. D may depend on either reservoir properties (e.g., any one, any combination, or all of geological geometry, rock properties; and fluid properties) in case of bottom-hole pressure being the observable quantities or well properties (e.g., any one, any combination, or all of diameter, friction factor, or fluid properties) in case of fluid rate production being the observable quantity.
Thus, in summary:
Thus, equations (17) and (18) provide one example representation in equation form of fluid movement. Other representations are contemplated, such as based on a reservoir model or a reservoir simulation. Henceforth, for simplicity, the dependence of y on x and z is suppressed in the above equations for purposes of compaction.
Further, the system may be dynamic and therefore dependent on time as shown in the following:
In one example, the system modeling may be represented as follows (with a more general set of equations than those listed above):
As such, the above equations may indicate how pressure (P1, P2, P3) at the bottomholes of different wells is changing with respect to time for a given injection rate(s) (qinj). As discussed below (see
In practicality, oil may be in tiny holes within rock in the reservoir. Increasing pressure in the reservoir may result in: (1) opening gateways within the rock to release the oil in the rock in the reservoir; and (2) creating a pressure gradient so that the oil can move to the bottomholes of one of the wells (e.g., the pressure is higher within the reservoir than at the bottomholes of one of the wells). Further, injecting gas into the reservoir may comprise huff and puff, resulting in two periods: (1) injecting fluid; and (2) after injecting fluid, stopping injecting fluid. While injecting fluid, the pressure may be highest at the bottomhole at the injector well(s). After injecting has stopped, and the injector well(s) may pump oil, the reservoir, which has had its pressure increase, may release some of its pressure so that oil in the reservoir moves toward lower pressure regions, such as to the bottomholes of the injector well(s) and/or the offset wells. In this way, some of the gas that was previously injected into the reservoir will be reproduced back (e.g., the oil that is pumped out may include some of the gas that was injected previously into the reservoir), thereby enabling recovery of at least some of the gas that was previously injected.
With regard to qinj, the gas injected into the reservoir via the injector well may change the pressure at the bottomhole injector well (as discussed above), and in turn, the pressure differential between the bottomholes of the injector well versus the offset well. More generally, the pressure at various points in the reservoir may likewise change. As discussed above, one option is to include a model having a set of partial differential equations that are very detailed, enabling modeling at every point in the subsurface and enabling modeling of the geology (e.g., permeability and/or porosity). However, to model such details of the pathways in the subsurface may be very computationally expensive. Alternatively, a more focused and limited model, such as the interwell connectivity model, may be based on a more limited set of inputs, and may be focused on a limited set of criteria (e.g., pressure, such as average pressure, at various parts of the subsurface, such as in the reservoir), thereby correlating any one, any combination, or all of the more limited set of inputs with any one, any combination, or all of a limited set of outputs (e.g., pressure and/or production). In one or some embodiments, the correlation may be based on the interwell connectivity metric. In this way, the more focused interwell connectivity model may provide the basis for an approximate pressure changes within the reservoir responsive to the huff and puff, enabling estimation of the reservoir performance. Further, as shown in the equations above, the interwell connectivity may be obtained in a simpler manner, such as by using Fcd, which is dependent (e.g., exponentially dependent) on average pressure (
In turn, the equations above may determine the production, such as the production from the offset well during huff, by determining production (q), which in one embodiment, may be time dependent (q(t)). Further, the equations above may provide a direct correlation between the gas injected (qinj) and the production (q), in effect providing a more direct connection between the controllable input(s), such as gas injected, with the one or more desired outputs, such as production.
As discussed above, an improvement or optimization model may be paired with a reservoir model. Further, as discussed above, various types of models are contemplated to represent the reservoir, including any one, any combination, or all of: a more-inclusive reservoir simulation model; a simplified model (as shown in the equations above, such as correlating qinj and q, such as based on an interwell connectivity metric); or a modified model (e.g., a machine learning model, such as a neural network that represents the subsurface). In one or some embodiments, the simplified model may include a correction factor (e.g., δ) to enable a less computationally intensive solution than a reservoir simulation model in determining the response in the reservoir to fluid injection.
Further, in one or some embodiments, the optimization model may have integrated therein any one, any combination, or all of: best practices; intuition; or knowledge, which may be manifested in rules or algorithmically. In particular, the optimization model may include one or more constraints (e.g., practical constraints and/or budgetary constraints) so that the generated outputs conform to expectations.
In practice, a wellbore may be drilled in order to aid in the exploration and recovery of various natural resources, such as oil and/or gas. The wellbore may be the hole that forms the well. A wellbore may be encased by materials such as steel and cement, or it may be uncased. As shown, the system includes the tubing 1312, which may be gas tight, and a production casing 1310, which may include a vertical section and a horizontal section. The tubing 1312 and the production casing 1310 may be formed as two concentric circles, with the volume in between forming the annulus. Further, hydraulic fractures 1320 may be formed from the production casing 1310. During production with natural flow (e.g., without any gas injection including huffing or artificial lift), hydrocarbons flow into the hydraulic fractures 1320 (shown as arrows 1330), then through the horizontal section of the production casing 1310 (shown as arrows 1332), and then through the tubing 1312 (shown as arrows 1334), and ultimately out of the tubing 1312 (shown as arrow 1336).
As discussed above, injecting fluid, such as gas, through the tubing 1312, into the wellbore (illustrated as gas injection through tubing 1362 which then travels via arrows 1364, 1366 from the wellbore into the hydraulic fractures, and from the hydraulic fractures into the rock matrix (shown as arrows 1368), thereby travelling to the subsurface in the reservoir. In this way, the injected gas may increase the pressure in the regions close or proximate to the hydraulic fractures 1320. Thus, in one or some embodiments, the injection of gas through tubing 1312 (an example of huffing) may result in the gas being injected into the rock matrix. In particular, the rock matrix comprise tightly packed rocks into which gas is injected, which in turn may assist in hydrocarbon flow trapped in the tightly packed rocks.
Alternatively, or in addition, the gas may be injected into the annulus. As shown in
As discussed above, additional data may be obtained at one or more times or time periods, such as during the primary depletion and/or subsequent cycles. In turn, the additional data may be used to update one or more models. For example, the analytical model 200 may be updated based on the additional data obtained. In particular, one or more parts of the analytical model 200, such as any one, any combination, or all of parameter(s), bias, or time lag(s) may be updated. In this regard, the analytical model 200 may comprise an initial model (e.g., modeling parameters, bias, time lag(s) via equations(s)) and may be tuned using additionally obtained data (e.g., via primary depletion and/or via cycle(s)).
Merely for example,
For example, in one or some embodiments, model calibration 1010, 1012, 1014 may comprise a model update module configured to update the one or more parts of the model based on additional data obtained (e.g., from drilling to primary depletion, to cycle 1, cycle 2, etc.). In a particular embodiment, the model update module may update any one, any combination, or all of: (i) model parameters (e.g., V, a, b); (ii) model bias (e.g., to incorporate missing or incomplete physics, such as A); or (iii) time lag(s) (e.g., time delay τ, time shift, etc.).
For example, in determining the values of the model parameters (e.g., any one, any combination, or all of: the length of time; timing; or rate of huff of the huff period and/or any one, any combination, or all of: the length of time; timing; or rate of the artificial lift period), the models may consider may consider one or more time lags, including any one, any combination, or all of: a time delay indicative of: (1) time delay indicative of a shift in the effect of an input on the system's output dynamic response; or (2) time shift used to determine improved or optimal timing for gas lift.
Merely for purposes of illustration, consider t=5 and τ=3. If injection is performed at t=2, the effects, due to the time lag, may be seen at time t=5. Knowing the time lag assists in configuring the injection strategy. τ may generally be unknown, but may be predicted. In this regard, τ may initially be estimated and iteratively updated.
With regard to (1), the time delay τ may be expressed as a time shift in the input (e.g., control) variable(s), such as gas injection rate (qinj). Merely by way of example, one manifestation of the time lag for (1) is illustrated in
In this regard, the response lag may be indicative of a time delay from injecting gas into the rock and the effect of the injection manifested in the pressure response in the offset wells (see, e.g.,
For (1), there may be any one, any combination, or all of the following three components: (a) delay of pressure response to injection; (b) delay to unsoldered temporal components; or (c) time it takes fluids to transport between wells.
As discussed above, various equations such as Equations (4)-(10), may relate to the response lag. In particular, modeling (c) may include Equations (8)-(9). Further, modeling both (a) and (b) may be included in the time delay/lag (see τ in the Equations above). In this regard, the delay for (1) may be a function of any one, any combination, or all of: rock properties; location of the offset wells relative to injector well; chemistry of the injected gas (e.g., rich vs. lean gas); or fluid properties.
With regard to (2), the time shift needed to determine an improved/optimal timing for gas lift may be reflected in an expanded system models beyond Equations (4)-(10). In this way, the time shift may be used in order to determine the delay of the gas lift in the well (e.g., until the gas lift is needed). This is illustrated, for example, in
Further, the model, such as the analytical model 200, may be used in combination with (such as embedded within or in conjunction with) an improvement or optimization model that may be tailored for one or more stages. For example,
In one embodiment, an operator inputs the constraint(s) of the system, such as the maximum oil rate constraint 1210. Alternatively, the design model 1020 determines the constraint(s) of the system, such as the maximum oil rate constraint 1210. Regardless, the design model may use the constraints of the system, the interwell connectivity metric, and the potential values for artificial lift and huff and puff in order to design the system itself (e.g., the parameters for drilling and/or construction of the wells, the mechanical hardware (e.g., compressor(s)); the piping; etc.). In this way, the design of the system comports with the constraint(s). Specifically, the design may avoid being oversized (e.g., the system being design for greater capacity than the maximum oil rate constraint 1210) so that the production never approaches the maximum oil rate constraint 1210.
In this regard, the design model 1020 is operated based on a limited understanding of the subsurface to determine the parameters of the system. In practice, the design model 1020 may generate a current best estimate as to the amount of hydrocarbons for extraction from the reservoir, determine a budget for drilling/construction of the system (e.g., $200 million for a specific pad), and select, from ranges of potential values, the values of the system (e.g., selecting the number of wells from a range of 5-20 for the maximum number of wells; select the piping from a range of piping from 3″ diameter to 5″ diameter). In one or some embodiments, the selected values may then determine the maximum oil rate constraint 1210.
Typically, production (e.g., barrels per day) decreases monotonically over time, as illustrated in curves 1040, 1120, 1220 without a gas injection stage. In contrast, the model(s) may configure the gas injection stage, such as huffing and/or artificial lift, in order to increase the production. In one or some embodiments, the gas injection stage includes multiple cycles, with the peak production in the different cycles being different (e.g., peak production increasing from cycle 1, to cycle 2, to cycle 3, with the peak production in cycle 3 being closest to the maximum oil rate constraint 1210, as shown in
At a certain time (which may be determined by a primary depletion model, not shown in
Thus, in one or some embodiments, the gas injection stage includes one or both of: (i) huff and puff (e.g., gas injected into the reservoir, such as via tubing 1312); or (ii) artificial lift (e.g., gas not directly injected into the tubing but travels into the tubing, such as via check valve(s) 1314). In one or some embodiments, for the same injector well, the same values for all of the parameters are used for huffing in the different cycles. Alternatively, for the same injector well, different values may be used for one, some, or all of the parameters of huffing in the different cycles (e.g., in order to increase production, such as illustrated in cycle 1, cycle 2, and cycle 3, different parameters, such as any one, any combination, or all of increased volume of gas injected, increased rate, or increased length of time may be used).
In one or some embodiments, for different injector wells: the same values for all of the parameters are used for huffing in the same cycle and/or in different cycles. Alternatively, for the different injector wells, different values may be used for one, some, or all of the parameters of huffing in the same cycle and/or in different cycles (e.g., because different interwell connectivity metrics may be present, the values for huff and puff for a first injector well may be different than for a second injector well, such as any one, any combination, or all of different timing of injection, different rates of injection, different lengths of time of injection, or different total volumes of injection).
In one or some embodiments, for the same well, the same values for all of the parameters for artificial lift are used for performing the artificial lift in the different cycles. Alternatively, for the same well, different values for one, some, or all of the parameters may be used to perform the artificial lift in the different cycles (e.g., in order to increase production, such as illustrated in cycle 1, cycle 2, and cycle 3).
In one or some embodiments, for different wells, the same values for all of the parameters for artificial lift are used for performing artificial lift in a same cycle and/or in different cycles. Alternatively, different values for one, some, or all of the parameters for artificial lift are used for performing artificial lift in a same cycle and/or in different cycles (e.g., because different interwell connectivity metrics may be present, the values for artificial lift for a first well may be different than for a second well, such as any one, any combination, or all of: (i) different numbers of artificial lifts in a single cycle (e.g., injector well or plugged offset well subject to a single artificial lift whereas an unplugged offset well is subject to multiple artificial lifts); (ii) different timing of artificial lift; (iii) different rates of artificial lift; (iv) different lengths of artificial lift; or (v) different total volumes of artificial lift).
In one or some embodiments, for a respective well subject to multiple artificial lifts in a single cycle, the same values for all of the parameters may be used for each artificial lift within the same cycle. Alternatively, different values for one, some, or all of the parameters may be used for each artificial lift within the same cycle (e.g., because of the effect of gas injected via injector well(s) and different interwell connectivity metrics, the parameters for the different artificial lifts may vary).
Further, as discussed above, within a respective cycle and/or across different cycles, a respective well may have any combination of the following: zero, one, or more than one huff stages; zero, one, or more than one natural flow stages; and zero, one, or more than one artificial lift stages. In the event that the respective well is not an injector well, zero huff stages are performed. In this instance, for example, one or more artificial lift stages may be performed along with one or more natural flow stages (e.g., see
Further, within a respective cycle and/or across different cycles, different wells may have the same or different combinations of huff stages, natural flow stages, and artificial lift stages. Merely by way of example, in the event that a first well is selected as an injector well and a second well is not selected as an injector well, the first well is assigned at least one huff stage (and optionally one or more natural flow stages and one or more artificial lift stages) whereas the second well is not assigned a huff stage. Further, the second well may be assigned one or more artificial lift stages with a respective cycle (such as at least two artificial lift stages, see
Thus, in order to determine the parameters of the gas injection stage, a gas injection model, which may include both the analytical model 200 and the improvement or optimization model tailored to the gas injection stage, may be used. In one embodiment, a single model is used to select the parameters for the entire gas injection stage. Alternatively, as shown in
For example, the annual planning model 1022 may be configured to optimize one or more aspects associated with huffing and puffing and/or artificial lift during a predetermined time period, such as annually. Further, the annual planning model 1022 may be configured to determine the parameters for multiple cycles, such as each of cycle 1, cycle 2, and cycle 3. As discussed above, additional data may be used to update the model. In this regard, after cycle 1, the model may be updated (see model calibration 1012), which may then be used for cycle operations model_1 1024, which may be used to determine the parameters for cycle 2 (with the parameters determined by cycle operations model_1 1024 being different in one or more aspects than the parameters determined by annual planning model 1022 for cycle 2 due to the updating of the model).
Further, within a respective cycle, daily operations model 1030, 1032, 1034 may be configured to improve or optimize operations on a predetermined basis, such as daily. By way of example, the system may have certain constraints, such as a limit on the amount of gas to inject and/or a limit on the amount of oil that should be produced (e.g., see maximum oil rate constraint 1210, discussed below). The daily operations model 1030, 1032, 1034 may be configured to control the system such that the constraints are met efficiently (e.g., limit the amount of artificial lift and/or huffing; choke back production).
In one or some embodiments, the models, such as annual planning model 1022, cycle operations model_1 1024, and/or cycle operations model_2 1026 may determine the sequence of periods and/or the length of time for the periods, such as the sequence and/or length of time for any one, any combination, or all of: the huff period; the natural flow period; or the artificial lift period. For example, the models may recommend a huff period (huff 1 1060, huff 2 1070, huff 3 1080) followed by a puff period (puff 1 1062, puff 2 1072, puff 3 1082). Further, the models may recommend one or more natural flow periods 1064, 1074, 1084 and one or more artificial lift periods 1066, 1076, 1086 within a respective puff period (puff 1 1062, puff 2 1072, puff 3 1082). As shown in
Further, the models may determine the length of each respective period, such as the length of any one, any combination, or all of: the huff period; the natural flow period; or the artificial lift period. Merely by way of example, the models may determine the length of time of huff 1 1060 to improve or optimize the hydrocarbon extraction during puff 1 1062. Alternatively, or in addition, the models may determine the length of time of natural flow 1064 and/or artificial lift 1066 during puff 1 1062 to improve or optimize the hydrocarbon extraction.
As such, in one or some embodiments, the models may determine both the sequence of the periods and the length of the respective periods, considering any one, any combination, or all of: the amount of gas for injection during the huff period (e.g., considering the interwell connectivity metric affecting the flow of gas in the subsurface); the length of time for the natural flow period (considering, based on the interwell connectivity metric, the dispersal rates of the injected gas); or the length of the artificial flow period.
As discussed above,
Thus, as shown in
In one or some embodiments, because the primary depletion stage does not inject gas (either into the reservoir via tubing or into the annulus), the model(s) may determine a potential need for artificial lift (e.g., injecting gas into the annulus) for offset wells that are not plugged after the primary depletion stage (such as immediately after the primary depletion stage). See 1110, 1112, 1114. Further, the model(s) may determine a length of time of the artificial lift stage(s). For example, as shown in
In particular, the model(s) may determine the length of time for a respective artificial lift period for an offset well based on the interwell connectivity metric of the respective offset well with respective injector well(s). As one example, a higher interwell connectivity metric, indicative that there is a greater fluid connection between the respective offset well and the respective injector well(s), may indicate that the gas injected during the huff period will travel more readily or more quickly from the respective injector well(s) to the respective offset well, thereby indicating that the artificial lift period for the offset well may be shorter than the huff period for the injector well (as shown in
As discussed above, one or more offset wells may be plugged during huffing, such as during huff 1 1060, huff 2 1070, and/or huff 3 1080. In one or some embodiments, the model(s) may determine which of the one or more offset wells to be plugged, such as based on the interwell connectivity metric. Merely by way of example, based on the interwell connectivity metric between a respective well (selected as an injector) and an offset well (e.g., the interwell connectivity metric indicates that injection of gas into the respective injector well will leak upward through the tubing of the offset well), the model(s) may determine which offset wells to plug. In effect, the proposed injector well communicates strongly (from a fluid standpoint) with a respective offset well so that a significant part (e.g., at least 30%; at least 40%; at least 50%; at least 60%; at least 70%; at least 80%; at least 90%) will flow to the respective offset well and be produced back. As such, plugging the offset well(s) is one way in which to contain the gas injected into the tubing. Under such circumstances, the respective offset well may be temporarily plugged. Conversely, in the event that the interwell connectivity metric between a proposed injector well and a proposed offset well is low such that the injected gas will not be produced back through the proposed offset well (less than 20% of injected fluid is produced back through the proposed offset well; less than 10%; less than 5%), the model may recommend not to plug the proposed offset well.
Also, the model(s) may determine the length of time to plug the one or more offset wells. As discussed above, plugging a well results in no hydrocarbon being extracted. As such, the model(s) are configured to weigh the costs of delaying extraction of hydrocarbon versus the possibility that injected gas will be produced via the offset wells. In particular, in one or some embodiments, the length of time to plug the one or more offset wells is identical to the time period of the huff stage (e.g., the length of time for huff 1 1060 is coextensive to and the same as the length of time for plugging a respective offset well). Alternatively, the length of time to plug the one or more offset wells is different than the time period of the huff stage. For example, in one or some embodiments, the length of time to plug a respective offset well may be less than the length of time for the huff stage.
In particular, huff 1 1060 may begin at t=X and end at t=Y. In one embodiment, the offset well may be plugged from t=X to t=Y (being coextensive and identical to huff 1 1060). Alternatively, the offset well may be plugged from t=X+Z to t=Y (being plugged later in time than the start of huff 1 1060, less than the total time period of huff 1 1060, but at least partly overlapping with the time period of huff 1 1060). Still alternatively, the offset well may be plugged from t=X+Z to t=Y+Z (being the same length as the time period of huff 1 1060, and at least partly overlapping with the time period of huff 1 1060). Yet alternatively, the offset well may be plugged from t=X+Z to t=Y+W, with W being less than Z (being a shorter length than the time period of huff 1 1060, but at least partly overlapping with the time period of huff 1 1060). Still yet alternatively, the offset well may be plugged from t=X+Z to t=Y+W, with W being greater than Z (being a longer length than the time period of huff 1 1060, and at least partly overlapping with the time period of huff 1 1060). Thus, in one or some embodiments, the model(s) may determine, such as based on the interwell connectivity metric(s), the length of the time in which the offset well is plugged and when the plug is inserted into the offset well relative to the huff for the injector well.
Further, similar to
Thus, in determining the values of the parameters (e.g., the length and/or timing of the huff period and/or the length and/or timing of the artificial lift period) illustrated in
With regard to (1), the time delay r may be expressed as a time shift in the input (e.g., control) variable(s), such as gas injection rate (qinj). Merely by way of example, one manifestation of the time lag for (1) is illustrated in
In this regard, the response lag may be indicative of a time delay from injecting gas into the rock and the effect of the injection manifested in the pressure response in the offset wells (see, e.g.,
For (1), there may be any one, any combination, or all of the following three components: (a) delay of pressure response to injection; (b) delay to unsoldered temporal components; or (c) time it takes fluids to transport between wells.
As discussed above, various equations such as Equations (4)-(10), may relate to the response lag. In particular, modeling (c) may include Equations (8)-(9). Further, modeling both (a) and (b) may be included in the time delay/lag (see τ in the Equations above). In this regard, the delay for (1) may be a function of any one, any combination, or all of: rock properties; location of the offset wells relative to injector well; chemistry of the injected gas (e.g., rich vs. lean gas); or fluid properties.
With regard to (2), the time shift may be needed to determine an improved/optimal timing for gas lift may be reflected in an expanded system models beyond Equations (4)-(10). In this way, the time shift may be used in order to determine the delay of the gas lift in the well (e.g., until the gas lift is needed). This is illustrated, for example, in
As discussed above,
Further,
Thus, as shown in
Further, the model(s) may determine for a respective cycle to perform at least one artificial lift (see
Alternatively, the model may recommend artificial lift for a plurality of wells (such as at least two wells, at least three wells, at least four wells; etc.) in a respective cycle, and may select for each respective well one, some or all of the following parameters for the artificial lift: timing of artificial lift; length of time of artificial lift; maximum rate of injection for artificial lift; rate of increase/decrease of artificial lift; type of gas injected; etc. In one embodiment, all of the parameters selected for artificial lift for two or more of the different wells are identical. Alternatively, all of the parameters selected for two or more of the different wells are different. Still alternatively, two or more of the different wells may differ in one or more aspects and may be the same in a remainder of the aspects. In such an instance, the model(s), in order to improve or optimize the use of the injected gas for artificial lift, may determine for the different wells, any one, any combination, or all of:
In addition, in one or some embodiments, the model(s) may determine for a respective cycle to include one artificial lift (see
It is noted that artificial lift 1110 may modify the pressure differential between the bottomhole and the wellhead for the offset well. In particular, there may be a lag τ in the effect of injecting gas into the reservoir since it may take time to build the pressure in the reservoir to a sufficient level to measure the impact on the production well. In this way, the lag τ may comprise the time period when the reservoir is affected by the gas injection sufficient to affect hydrocarbon production. In one or some embodiments, the interwell connectivity model may be used to determine a length of the lag τ (e.g., the length of time to achieve the desired reservoir pressure), and in turn, the length of the gas lift in order to compensate for the lag τ (see artificial lift). Though, it is noted that artificial lift 1110 may not necessarily be needed at the beginning of each respective cycle. In one or some embodiments, the lag τ may be determined by solving an objective function to obtain a value or a range for the lag τ. In turn, the solution for the lag τ may improve through model calibration.
Alternatively, the model(s) may select all of the parameters for each artificial lift within the single cycle for a single well to be different. Still alternatively, the two or more artificial lifts within a single cycle for a single well may differ in one or more aspects and may be the same in a remainder of the aspects. In such an instance, the model(s), in order to improve or optimize the use of the injected gas for artificial lifts within a single cycle for a single well, may determine any one, any combination, or all of:
Similarly, the model(s) may recommend artificial lifts for a respective well in different cycles. See 1066, 1076, 1086 in
In one or some embodiments, system model 1 1420 may comprise a model of one or more aspects of the system. For example, the system may include various parts for the surface, with one or more surface models associated with the various parts. In particular, the system may comprise a section from the wells to the manifold, from the manifold to the producing facility, one or more compressors, and the like. In this way, the surface model(s) may be associated with various operations on the surface, such as flow between well heads, gas compressors, dehydrators, etc. The system model may comprise a combination of surface model(s), gas lift model(s) (e.g., describing the flow from the surface to the bottomhole via the annulus of wells), and subsurface models (e.g., an interwell connectivity model that describes flow near injectors and between injector and offset wells during gas injection (huff) and production (puff)). Thus, the system model may comprise one or more models, which integrate the interwell connectivity model with the model of the one or aspects of the system, enabling prediction of the response of the system to various inputs (e.g., injecting gas in a particular well in the system).
As discussed above, design optimization 1410 may comprise design model 1020 and may determine one or more parameters regarding the development of the field (e.g., (1) the number of wells for drilling; (2) the spacing between the wells drilled; (3) the well design parameters (4) the specifics of completions; etc.). Further, the annual plan optimization 1412 may comprise annual planning model 1022 and may determine one or more parameters for an upcoming year of operation. Cycle operation optimization 1414 may comprise one or both of cycle operations model_1 1024 or cycle operations model_1 1026 and may determine one or more parameters for a respective cycle of operations. A model for daily operations optimization 1416 may comprise any one, any combination, or all of daily operations model 1030, daily operations model 1032, or daily operations model 1034 and may determine one or more parameters for daily operations with a respective cycle.
As discussed above, the optimization model(s) may comprise flow model(s) that optionally constrains one or more individual components (e.g., any one, any combination, or all of gas lift gas rate, compression capacity, flow capacity imposed by choke set points at wellheads, etc.). In one or some embodiments, optimization controls and objectives may be different for each optimization model. By way of example, the cycle operation optimization 1414 may focus on optimizing oil production within a respective cycle, and determine the controls for various operations, such as, for example, gas injection volume. Likewise, the daily operation optimization 1416 may focus on optimizing oil production within on a daily basis, and determine the controls for various operations within a respective day, such as, for example, choke or gas lift rate. In contrast, annual plan optimization 1412 may focus on longer term strategic planning across multiple cycles (e.g., how much gas volume is needed within a respective year; how large of a compressor is needed for the respective year). Thus, using the various optimization models, optimization may be performed in presence of uncertainty (e.g., uncertainty associated with parameters V, a, b etc., with optimization performed by analyzing different scenarios of the parameters).
In one or some embodiments, the data input(s), such as the data related to gas injection, may be generated from one or more optimization models including any one, any combination, or all of: annual plan optimization 1412, cycle operation optimization 1414, or daily operation optimization 1416. In one or some embodiments, the input(s) regarding production system design parameters may comprise any one, any combination, or all of: number of wells; well placement; well survey; pipeline topology; number of compressors; or size of compressors. In one or some embodiments, the input(s) regarding reservoir parameters include any one, any combination, or all of: reservoir parameters themselves; well connectivity (e.g., a, b); or volumes (V1, V2, V3), which may be from Model Update Module 1430. Alternatively, or in addition, the input(s) regarding reservoir parameters may comprise one or both of reservoir fluids or PVT data.
As shown in
Further, as discussed above with regard to
At 1604, it is determined whether to perform optimization of discrete variables. In particular, optimization of discrete variables may be performed in one of several ways. In one way, a potentially non-linear objective function may be simplified, such as by substituting a piecewise linear function, which may provide an estimate for the discrete variables. After which, the piecewise linear function may be examined for error, and iteratively modified until the error is less than a predetermined value.
Further, if optimization of the discrete variables is not to be performed, at 1606, sweeping for discrete variables is performed. For example, the solution space may be reduced by eliminating infeasible solutions, with the user sweeping a specific area of the solution space to select the values for the discrete variables.
Further, it may be determined to optimize the continuous variables. If so, at 1608, optimization is performed, thereafter at 1610, function calculation is performed, and thereafter at 1612, a HnP simulation model is run to calculate the conditional value at risk (CVaR) net present value (NPV). Through the loop of 1608, 1610, 1612, it may be determined whether to continue iterating to optimize the values selected for the continuous variables. Thus, in one or some embodiments, optimization of both the discrete variables and the continuous variables may be performed at the same time.
If at 1604, it is determined that the optimization of discrete variables has been performed, at 1614, it is determined whether the best discrete variables are integer. If so, flow diagram 1600 ends. If not, at 1616, a new sub-problem is created, and flow diagram 1600 iterates back to 1602 to initialize.
As discussed above, control of gas injected into the reservoir may create predetermined pressure in one or more parts of the subsurface, such as predetermined pressure differentials between different parts of the subsurface (e.g., between the reservoir and one or more bottomholes). Thus, via gas injection into the subsurface, a predetermined pressure profile (and predetermined pressure gradient(s)) in the subsurface may be created. Further, control of gas lift may create a predetermined pressure differential within a respective well (e.g., between the bottomhole and the wellhead of the respective well). In this way, a predetermined pressure path, with one or more predetermined pressure gradients, may be created from the reservoir to the wellhead. As discussed previously, the interwell connectivity model may be used to manage the injection of gas into the subsurface and may be used to determine whether (or when) to perform the gas lift.
Thus, when injecting gas near or proximate to the reservoir, pressure increases in the reservoir, creating the requisite pressure differential. Further, gas lift within a nearby well (whether in an offset well during and after gas injection and/or in an injector well after gas injection) may be performed to complement or be in concert with the created pressure differential in the subsurface in order to guide the flow of hydrocarbons from the reservoir to the wellhead. Further, the gas lift for a respective well may be performed in a selective or an optimized manner dependent on one or more factors, such as the amount of hydrocarbons flowing in the respective well and/or the pressure differential within the subsurface. In this way, the gas lift, which its attendant costs, may be performed only when needed.
In particular, unlike a process that may simultaneously inject gas into the reservoir and into the annulus (for gas lift), the disclosed methodology may be used to determine whether, and when, to perform one of the gas processes (e.g., one of the gas injection into the reservoir or gas lift), to perform both of the gas processes (e.g., both of the gas injection into the reservoir or gas lift), or to perform neither of the gas processes, in an effort to coordinate the gas injection and/or gas lift to get the hydrocarbons from the reservoir to the surface. This is illustrated above, for example, with regard to
In this way, the interwell connectivity model may be used in a variety of contexts, such as a predictive model (e.g., certain set of inputs generates a certain set of outputs, or vice-versa, such as illustrated in
Further, the flow in various parts of the subsurface may be represented in one of several ways. For example, the flow in the reservoir (e.g., from reservoir 1750 to offset well 1710) may be represented in equation form (e.g., see equations (17)-(18) above), in model form, or via reservoir simulation. As another example, the flow within a well (e.g., within offset well 1710) may be represented by a hydraulic model. In this regard, one or more models (one or more of which may be based on the interwell connectivity metric) may be used to indicate the flow of fluid in various parts of the subsurface.
In all practical applications, the present technological advancement must be used in conjunction with a computer, programmed in accordance with the disclosures herein. For example,
The computer system 1800 may also include computer components such as non-transitory, computer-readable media. Examples of computer-readable media include computer-readable non-transitory storage media, such as a random-access memory (RAM) 1806, which may be SRAM, DRAM, SDRAM, or the like. The computer system 1800 may also include additional non-transitory, computer-readable storage media such as a read-only memory (ROM) 1808, which may be PROM, EPROM, EEPROM, or the like. RAM 1806 and ROM 1808 hold user and system data and programs, as is known in the art. The computer system 1800 may also include an input/output (I/O) adapter 1810, a graphics processing unit (GPU) 1814, a communications adapter 1822, a user interface adapter 1824, a display driver 1816, and a display adapter 1818.
The I/O adapter 1810 may connect additional non-transitory, computer-readable media such as storage device(s) 1812, including, for example, a hard drive, a compact disc (CD) drive, a floppy disk drive, a tape drive, and the like to computer system 1800. The storage device(s) may be used when RAM 1806 is insufficient for the memory requirements associated with storing data for operations of the present techniques. The data storage of the computer system 1800 may be used for storing information and/or other data used or generated as disclosed herein. For example, storage device(s) 1812 may be used to store configuration information or additional plug-ins in accordance with the present techniques. Further, user interface adapter 1824 couples user input devices, such as a keyboard 1828, a pointing device 1826 and/or output devices to the computer system 1800. The display adapter 1818 is driven by the CPU 1802 to control the display on a display device 1820 to, for example, present information to the user such as subsurface images generated according to methods described herein.
The architecture of computer system 1800 may be varied as desired. For example, any suitable processor-based device may be used, including without limitation personal computers, laptop computers, computer workstations, and multi-processor servers. Moreover, the present technological advancement may be implemented on application specific integrated circuits (ASICs) or very large scale integrated (VLSI) circuits. In fact, persons of ordinary skill in the art may use any number of suitable hardware structures capable of executing logical operations according to the present technological advancement. The term “processing circuit” encompasses a hardware processor (such as those found in the hardware devices noted above), ASICs, and VLSI circuits. Input data to the computer system 1800 may include various plug-ins and library files. Input data may additionally include configuration information.
Preferably, the computer is a high-performance computer (HPC), known to those skilled in the art. Such high-performance computers typically involve clusters of nodes, each node having multiple CPU's and computer memory that allow parallel computation. The models may be visualized and edited using any interactive visualization programs and associated hardware, such as monitors and projectors. The architecture of system may vary and may be composed of any number of suitable hardware structures capable of executing logical operations and displaying the output according to the present technological advancement. Those of ordinary skill in the art are aware of suitable supercomputers available from Cray or IBM or other cloud computing based vendors such as Microsoft, Amazon.
The above-described techniques, and/or systems implementing such techniques, can further include hydrocarbon management based at least in part upon the above techniques, including using the AI model in one or more aspects of hydrocarbon management. For instance, methods according to various embodiments may include managing hydrocarbons based at least in part upon the one or more generated AI models and data representations constructed according to the above-described methods. In particular, such methods may include performing various welds in the context of drilling a well, and/or causing a well to be drilled, based at least in part upon the one or more generated geological models and data representations discussed herein (e.g., such that the well is located based at least in part upon a location determined from the models and/or data representations, which location may optionally be informed by other inputs, data, and/or analyses, as well) and further prospecting for and/or producing hydrocarbons using the well.
It is intended that the foregoing detailed description be understood as an illustration of selected forms that the invention can take and not as a definition of the invention. It is only the following claims, including all equivalents which are intended to define the scope of the claimed invention. Further, it should be noted that any aspect of any of the preferred embodiments described herein may be used alone or in combination with one another. Finally, persons skilled in the art will readily recognize that in preferred implementation, some, or all of the steps in the disclosed method are performed using a computer so that the methodology is computer implemented. In such cases, the resulting physical properties model may be downloaded or saved to computer storage.
The following example embodiments of the invention are also disclosed.
Embodiment 1: A computer-implemented method for enhanced oil recovery (EOR) for a plurality of wells in one or more intervals, the method comprising:
Embodiment 2: The method of embodiment 1,
Embodiment 3: The method of any of embodiments 1 or 2,
Embodiment 4: The method of any of embodiments 1-3,
Embodiment 5: The method of any of embodiments 1-4,
Embodiment 6: The method of any of embodiments 1-5,
Embodiment 7: The method of any of embodiments 1-6,
Embodiment 8: The method of any of embodiments 1-7,
Embodiment 9: The method of any of embodiments 1-8
Embodiment 10: The method of any of embodiments 1-9
Embodiment 11: The method of any of embodiments 1-10,
Embodiment 12: The method of any of embodiments 1-11,
Embodiment 13: The method of any of embodiments 1-12,
Embodiment 14: The method of any of embodiments 1-13,
Embodiment 15: The method of any of embodiments 1-14,
Embodiment 16: The method of any of embodiments 1-15,
Embodiment 17: The method of any of embodiments 1-16,
Embodiment 18: The method of any of embodiments 1-17,
Embodiment 19: The method of any of embodiments 1-18,
Embodiment 20: The method of any of embodiments 1-19,
Embodiment 21: The method of any of embodiments 1-20,
Embodiment 22: The method of any of embodiments 1-21,
Embodiment 23: The method of any of embodiments 1-22,
Embodiment 24: The method of any of embodiments 1-23,
Embodiment 25: A non-transitory computer readable medium having stored thereon software instructions that, when executed by a processor, cause the processor to perform the method of any of embodiments 1-24.
Embodiment 26: A system comprising a processor and a memory, the processor in communication with the memory, the memory having stored thereon software instructions that, when executed by the processor, cause the processor to perform the method of any of embodiments 1-24.
Embodiment 27: A method for hydrocarbon extraction comprising:
Embodiment 28 The method of embodiment 27,
Embodiment 29: The method of any of embodiments 17 or 28,
Embodiment 30: The method of any of embodiments 27-29,
Embodiment 31: The method of any of embodiments 27-30,
Embodiment 32: The method of any of embodiments 27-31,
Embodiment 33: The method of any of embodiments 27-32,
Embodiment 34: The method of any of embodiments 27-33,
Embodiment 35: The method of any of embodiments 27-34,
Embodiment 36: The method of any of embodiments 27-35,
Embodiment 37: The method of any of embodiments 27-36,
Embodiment 38: The method of any of embodiments 27-37,
Embodiment 39: The method of any of embodiments 27-38,
Embodiment 40: The method of any of embodiments 27-39,
Embodiment 41: The method of any of embodiments 27-40,
Embodiment 42: The method of any of embodiments 27-41,
Embodiment 43: The method of any of embodiments 27-42,
Embodiment 44: The method of any of embodiments 27-43,
Embodiment 45: The method of any of embodiments 27-44,
Embodiment 46: The method of any of embodiments 27-45,
Embodiment 47: The method of any of embodiments 27-46,
Embodiment 48: The method of any of embodiments 27-47,
Embodiment 49: The method of any of embodiments 27-48,
Embodiment 50: The method of any of embodiments 27-49,
Embodiment 51: A non-transitory computer readable medium having stored thereon software instructions that, when executed by a processor, cause the processor to perform the method of any of embodiments 27-50.
Embodiment 52: A system comprising a processor and a memory, the processor in communication with the memory, the memory having stored thereon software instructions that, when executed by the processor, cause the processor to perform the method of any of embodiments 27-50.
This application claims the benefit of U.S. Provisional Application Ser. No. 63/368,690, entitled “METHODOLOGY FOR DESIGN AND OPERATIONS OF FIELD-WIDE AND MULTI-WELL ENHANCED OIL RECOVERY OF UNCONVENTIONAL HYDROCARBON ASSETS,” filed Jul. 18, 2022, and the benefit of U.S. Provisional Application Ser. No. 63/368,692, entitled “METHODOLOGY FOR DESIGN AND OPERATIONS OF FIELD-WIDE AND MULTI-WELL ENHANCED OIL RECOVERY OF UNCONVENTIONAL HYDROCARBON ASSETS,” filed Jul. 18, 2022, the disclosures of which are hereby incorporated by reference in their entirety.
Number | Date | Country | |
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63368690 | Jul 2022 | US |