Patent Application
20110246163
The present disclosure relates generally to systems and methods for optimizing well operating plans and systems designed thereby. More specifically, the present disclosure relates to optimizing well operating plans by optimizing well potential relative to effective production capacity in light of dynamic reservoir conditions, dynamic near-well conditions, and dynamic well conditions over space and time.
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
To facilitate further discussion of the hydrocarbon recovery operations,
The floating production facility 102 may be configured to monitor and produce hydrocarbons from the production intervals 108a-108n of the subsurface formation 107. The floating production facility 102 may be a floating vessel capable of managing the production of fluids, such as hydrocarbons, from subsea wells. These fluids may be stored on the floating production facility 102 and/or provided to tankers (not shown). To access the production intervals 108a-108n, the floating production facility 102 is coupled to a subsea tree 104 and control valve 110 via a control umbilical 112. The control umbilical 112 may include production tubing for providing hydrocarbons from the subsea tree 104 to the floating production facility 102, control tubing for hydraulic or electrical devices, and/or a control cable for communicating with other devices within the well 114.
To access the production intervals 108a-108n, the well 114 penetrates the sea floor 106 to a depth that interfaces with the production intervals 108a-108n at different depths (or lengths in the case of horizontal or deviated wells) within the well 114. As may be appreciated, the production intervals 108a-108n, which may be referred to as production intervals 108, may include various layers or intervals of rock that may or may not include hydrocarbons and may be referred to as zones. The subsea tree 104, which is positioned over the well 114 at the sea floor 106, provides an interface between devices within the well 114 and the floating production facility 102. Accordingly, the subsea tree 104 may be coupled to a production tubing string 128 to provide fluid flow paths and a control cable (not shown) to provide communication paths, which may interface with the control umbilical 112 at the subsea tree 104.
Within the well 114, the production system 100 may also include different equipment to provide access to the production intervals 108a-108n. For instance, a surface casing string 124 may be installed from the sea floor 106 to a location at a specific depth beneath the sea floor 106. Within the surface casing string 124, an intermediate or production casing string 126, which may extend down to a depth near the production interval 108a, may be utilized to provide support for walls of the well 114. The surface and production casing strings 124 and 126 may be cemented into a fixed position within the well 114 to further stabilize the well 114. Within the surface and production casing strings 124 and 126, a production tubing string 128 may be utilized to provide a flow path through the well 114 for hydrocarbons and other fluids. A subsurface safety valve 132 may be utilized to block the flow of fluids from portions of the production tubing string 128 in the event of rupture or break above the subsurface safety valve 132. Further, packers 134 may be utilized to isolate specific zones within the well annulus from each other. The packers 134 may be configured to provide fluid communication paths between surface and the sand control devices 138a-138n, while preventing fluid flow in one or more other areas, such as a well annulus.
In addition to the above equipment, other equipment, such as sand control devices 138a-138n, may be utilized to manage the flow of fluids from within the well. In particular, the sand control devices 138a-138n may be utilized to manage the flow of fluids and/or particles into the production tubing string 128. The sand control devices 138a-138n may include slotted liners, stand-alone screens (SAS), pre-packed screens, wire-wrapped screens, membrane screens, expandable screens, and/or wire-mesh screens. The sand control devices 138a-138n may also include inflow control mechanisms, such as inflow control devices (e.g. valves, conduits, nozzles, or any other suitable mechanisms), which may increase pressure loss along the fluid flow path. Still additionally, gravel packs may be implemented together with the sand control devices. The sand control devices 138a-138n may include different components or configurations for any two or more of the intervals 108a-108n of the well to accommodate varying conditions along the length of the well. For example, the intervals 108a-108b may include a cased-hole completion and a particular configuration of sand control devices 138a-138b while interval 108n may be an open-hole interval of the well having a different configuration for the sand control device 138n.
Conventionally, packers or other flow control mechanisms are disposed between adjacent intervals 108 to enable adjacent intervals to be completed differently, such as including sand control in one interval while not in an adjacent interval. While multiple interval wells are relatively common, and while the completions within the different intervals may be different, the planning associated with the design of these completions is generally based on a relatively limited set of information. For example, the design may include sand control equipment in one interval and not in another based solely on observations about the type of rock in the interval or on experiences in nearby wells. Other aspects of conventional well completion design will be understood from the following discussion.
While hydrocarbons have been a source of energy for many years, the technology available for use in extracting hydrocarbons from the ground continues to evolve. In part, the need for continually advancing technology comes from the increasingly challenging circumstances in which hydrocarbons are found. For example, more and more wells are located in areas that are geographically challenging. Geographic complexities, such as reservoirs in arctic conditions, in deep water, or in otherwise challenging subsurface formations (sandy, unconsolidated formations, shale formations, etc.), can increase the costs and operational risks of drilling a well and of treating the well should hydrocarbon production fall below acceptable limits or should there be another problem with the well (such as sand or water production). Even in otherwise conventional fields and formations, the costs of workovers and other treatments are high. In addition to the lost revenues while the well is not producing at target rates, the costs of equipment and manpower during workovers and other treatments can run into millions of dollars. Accordingly, researchers are continually attempting to identify ways to improve the efficiency of wells and reservoirs.
One measure of the efficiency of a well or reservoir is the dollars invested per quantity of oil produced. Clearly, the efficiency is reduced as costs and risks are increased through workovers and other treatments. However, efficiency is also reduced when production rates and/or total production volumes are low. Accordingly, well operators typically attempt to build robust wells, to postpone workovers and treatments, and to produce at rates that will return the greatest total volume with the lowest maintenance costs. While these goals are obvious in themselves, accomplishing these goals is far from easy due to the complexity of the operations.
From a very simplified perspective, hydrocarbon operations include effectively two primary components: 1) the reservoir in which hydrocarbons are stored; and 2) the well through which hydrocarbons are produced to the surface. Well operators take the reservoir in the condition provided by nature. As used herein, the term “well operators” is used generically to refer to the multitude of personnel involved in the production of hydrocarbons including geoscientists, reservoir engineers, drilling personnel, completions personnel, treatment personnel, business managers and planners, etc. In contrast, operators go to great length to engineer the well and to operate it in a manner that will maximize production. The well is the component that the well operators can manipulate, treat, modify, etc. to control the rate at which fluids are produced to the surface. As used herein, the term “well” is used broadly to refer to the wellbore itself (the hole created through drilling operations) and the equipment installed, disposed, or used in the well.
While the reservoir consists of the rock and natural earth into which the well is drilled, it may be understood as having two component parts: the near-well region and the native reservoir. As is well understood, the term reservoir is used herein to refer to regions of the earth in which hydrocarbons or hydrocarbon precursors are disposed or stored. In some implementations, the well drilled to connect to the reservoir may intersect the reservoir directly. In other implementations, the well may be disposed near the reservoir and be operatively connected to the reservoir through a variety of conventional means. Regardless of the relationship between the well and the physical location of the hydrocarbons, the drilling, the completion, and/or the existence of the well often affects the nature of the formation in the area adjacent the well rendering the near-well region distinct from the native reservoir in at least one manner, as is well understood by those in the industry. For the purposes of the present disclosure, the term near-well region refers to those portions of the formation that are affected by operations in the wellbore, such as drilling operations, completion operations, injection operations, fracture operations, acid treatments, etc.
While this relationship between the well, the near-well, and the reservoir has been appreciated for many years, conventional methods for designing wells and well operating plans, including completions and production operations, do not account for the dynamic behavior that affects well performance during the life of a well. For example, the near-well region that is the most dynamic portion of the formation is not distinguished from the reservoir during the reservoir modeling used to predict production rates and volumes. While reservoir models are increasing in sophistication, completion details and near-well phenomena are either neglected entirely or given simplistic treatment. For example, most reservoir models treat wells as boundary conditions providing an inlet to or an outlet from the overall reservoir system rather than the complex combination of equipment disposed in and methods performed on a well. Drilling operations and completion procedures, such as perforating, gravel packing, hydraulic fracturing, acidizing, etc., are, when considered, considered merely by means of a mathematical correction factor commonly referred to as a “skin factor.” Complex completions equipment are commonly neglected entirely in predicting production performance of a reservoir. In many circumstances, reservoir engineers determine predicted production performances with an assumed skin factor establishing the performance expectations. The drilling and subsurface engineers are then expected to provide a completed well with a skin factor less than the factor used in the assumptions. In many implementations, the estimated skin factor of the final completion design is never incorporated into the reservoir simulations for more accurate production performance predictions.
While the inflow performance analysis 200 of
Additionally, many operators now recognize the desirability of multi-zone or multi-interval wells and may vary the well completion and/or operating conditions along the contact length of the well. Accordingly, the inflow performance analysis 200 may be performed for each interval to identify target operating conditions for that interval.
While such planning and design methods have worked relatively well in the past, they are focused on making the initial completion designs and on maintaining production rates and volumes at levels established before the well is drilled. For example, while certain production problems may have presented themselves at a given time in a first well, by the time the second well, which is designed based on the experiences of the first well, reaches that given time in its life, the reservoir has changed dramatically through continued production operations and resultant depletion.
Thus far, much of the discussion has focused on designing wells and completions so as to maximize the initial production. While the balance between reservoir potential and well potential is important in the construction and completion of new wells, it is also important in considering proposed workovers of wells that are already suffering reduced production rates. For example, the relative impacts of different workover procedures and/or different completion equipment that may be installed during the workover may be considered. While these impacts are considered today, the consideration is limited to the same types of analysis described above—considering the inflow performance rate of the reservoir on average and the average tubular performance rate. In short, the conventional methods fail to adequately consider: 1) the range of completions technologies available; 2) the ability to customize the completion along the length of the well; and 3) the changes that occur in a well and in the near-well region as a reservoir is produced.
Well operators, and particularly completions engineers, are constantly challenged to produce wells at the highest rate possible and to extract the maximum total hydrocarbons possible from a reservoir. These objectives are often in conflict as producing a given well at high current rates may present risks to the well and/or to the reservoir. For example, a reservoir may have a high reservoir potential, which may be considered to be the potential or driving force moving fluids towards a well. A well completion designed to minimize the skin so as to allow maximum flow into the well may result in high initial production rates from such a reservoir. However, the same completion having low skin disposed in a poorly consolidated formation may lead to sand production in the well. Such a well would have high production rates for a short period of time before production is reduced due to excess sand production. Sand production is one of many challenges or obstacles that may be confronted when wells are designed merely to maximize initial hydrocarbon production rates.
These risks and challenges to maximizing total production are recognized by the industry. Various tools and equipment have been developed to provide complex completions in an effort to control the flow of fluids to maximize production while minimizing workovers. As introduced above, wells having multiple isolated intervals are common. Additionally, various examples of adaptable completions have been proposed, including completion equipment that is controllable from the surface and completion equipment that self-adapts under varying conditions in the well.
The increasing complexity of modern fields and reservoirs and the increasing complexity of modern wells and well technology have rendered the conventional well production planning tools insufficient for optimizing modern operations. While any of the various completions equipment configurations and methods may be applied in a given well to obtain or pursue optimized production rates, the challenge remains in identifying which type to use, how to configure the equipment, and where in the well it should be disposed for maximum cost benefit. Additionally, because the impact of the completion and/or workover decisions and operations on the formation is not reflected in the reservoir models of the conventional methods, it is not possible to determine how much more production, either in current rate or total volume, might be available through continued improvements to the completion.
The foregoing discussion of need in the art is intended to be representative rather than exhaustive. Technology addressing one or more such needs, or some other related shortcoming in the field, would benefit well planning and reservoir development planning, for example, providing decisions or plans for constructing, completing, operating, and/or treating a well and/or developing a reservoir more effectively and more profitably.
The present disclosure provides methods for hydrocarbon well decision-making. The methods include: characterizing reservoir potential of a reservoir over space and time using a reservoir model; characterizing near-well capacity of a formation adjacent to a well drilled to access the reservoir using a near-well model of a simulated well accessing the reservoir; characterizing an effective production capacity based at least in part on the characterized reservoir potential and the characterized near-well capacity; determining an optimized well potential over space and time relative to the characterized effective production capacity using a well model of the simulated well accessing the reservoir; and determining at least one well operating plan component that can be incorporated into a well operating plan to provide the optimized well potential in a well accessing the reservoir.
Additionally, the present disclosure provides systems associated with the production of hydrocarbons. The systems include a well operatively connected to a subsurface reservoir. The well includes at least one component selected based at least in part on a computerized simulation adapted to: 1) characterize reservoir potential of the reservoir over space and time using a reservoir model; 2) characterize near-well capacity of a formation adjacent to the well using a near-well model of a simulated well accessing the reservoir; 3) characterize an effective production capacity based at least in part on the near-well capacity and the reservoir potential; 4) determine an optimized well potential over space and time relative to the characterized effective production capacity using a well model of the simulated well accessing the reservoir; and 5) determine at least one component that can be incorporated into a well operating plan to provide the optimized well potential in the well.
Additionally, the present disclosure provides systems for optimizing hydrocarbon well decision-making. Exemplary systems include: a processor; a storage medium; and a computer application accessible by the processor and stored on at least one of the storage medium and the processor. The computer application is adapted to: 1) characterize reservoir potential of the reservoir over space and time using a reservoir model; 2) characterize near-well capacity of a formation adjacent to the well using a near-well model of a simulated well accessing the reservoir; 3) characterize an effective production capacity based at least in part on the near-well capacity and the reservoir potential; 4) determine an optimized well potential over space and time relative to the characterized effective production capacity using a well model of the simulated well accessing the reservoir; and 5) determine at least one component that can be incorporated into a well operating plan to provide the optimized well potential in the well.
The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and specific embodiment disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims. The novel features which are believed to be characteristic of the invention, both as to its organization and method of operation, together with further objects and advantages will be better understood from the following description when considered in connection with the accompanying figures. It is to be expressly understood, however, that each of the figures is provided for the purpose of illustration and description only and is not intended as a definition of the limits of the present invention.
While the present disclosure is susceptible to various modifications and alternative forms, specific exemplary implementations thereof have been shown in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific exemplary implementations is not intended to limit the disclosure to the particular forms disclosed herein. This disclosure is to cover all modifications and equivalents as defined by the appended claims. It should also be understood that the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating principles of exemplary embodiments of the present invention. Moreover, certain dimensions may be exaggerated to help visually convey such principles. Further where considered appropriate, reference numerals may be repeated among the drawings to indicate corresponding or analogous elements. Moreover, two or more blocks or elements depicted as distinct or separate in the drawings may be combined into a single functional block or element. Similarly, a single block or element illustrated in the drawings may be implemented as multiple steps or by multiple elements in cooperation.
The words and phrases used herein should be understood and interpreted to have a meaning consistent with the understanding of those words and phrases by those skilled in the relevant art. No special definition of a term or phrase, i.e., a definition that is different from the ordinary and customary meaning as understood by those skilled in the art, is intended to be implied by consistent usage of the term or phrase herein. To the extent that a term or phrase is intended to have a special meaning, i.e., a meaning other than the broadest meaning understood by skilled artisans, such a special or clarifying definition will be expressly set forth in the specification in a definitional manner that provides the special or clarifying definition for the term or phrase.
For example, the following discussion contains a non-exhaustive list of definitions of several specific terms used in this disclosure (other terms may be defined or clarified in a definitional manner elsewhere herein). These definitions are intended to clarify the meanings of the terms used herein. It is believed that the terms are used in a manner consistent with their ordinary meaning, but the definitions are nonetheless specified here for clarity.
A/an: The indefinite articles “a” and “an” as used herein mean one or more when applied to any feature in embodiments and implementations of the present invention described in the specification and claims. The use of “a” and “an” does not limit the meaning to a single feature unless such a limit is specifically stated. The term “a” or “an” entity refers to one or more of that entity. As such, the terms “a” (or “an”), “one or more” and “at least one” can be used interchangeably herein.
About: As used herein, “about” refers to a degree of deviation based on experimental error typical for the particular property identified. The latitude provided the term “about” will depend on the specific context and particular property and can be readily discerned by those skilled in the art. The term “about” is not intended to either expand or limit the degree of equivalents which may otherwise be afforded a particular value. Further, unless otherwise stated, the term “about” shall expressly include “exactly,” consistent with the discussion below regarding ranges and numerical data.
Above/below: In the following description of the representative embodiments of the invention, directional terms, such as “above”, “below”, “upper”, “lower”, etc., are used for convenience in referring to the accompanying drawings. In general, “above”, “upper”, “upward” and similar terms refer to a direction toward the earth's surface along a wellbore, and “below”, “lower”, “downward” and similar terms refer to a direction away from the earth's surface along the wellbore. Continuing with the example of relative directions in a wellbore, “upper” and “lower” may also refer to relative positions along the longitudinal dimension of a wellbore rather than relative to the surface, such as in describing both vertical and horizontal wells.
And/or: The term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple elements listed with “and/or” should be construed in the same fashion, i.e., “one or more” of the elements so conjoined. Other elements may optionally be present other than the elements specifically identified by the “and/or” clause, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, a reference to “A and/or B”, when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A only (optionally including elements other than B); in another embodiment, to B only (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements). As used herein in the specification and in the claims, “or” should be understood to have the same meaning as “and/or” as defined above. For example, when separating items in a list, “or” or “and/or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of” or “exactly one of,” or, when used in the claims, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e. “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of,” “only one of,” or “exactly one of.”
Any: The adjective “any” means one, some, or all indiscriminately of whatever quantity.
At least: As used herein in the specification and in the claims, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements). The phrases “at least one”, “one or more”, and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C”, “at least one of A, B, or C”, “one or more of A, B, and C”, “one or more of A, B, or C” and “A, B, and/or C” means A alone, B alone, C alone, A and B together, A and C together, B and C together, or A, B and C together.
Based on: “Based on” does not mean “based only on”, unless expressly specified otherwise. In other words, the phrase “based on” describes both “based only on,” “based at least on,” and “based at least in part on.”
Comprising: In the claims, as well as in the specification, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.
Couple: Any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.
Determining: “Determining” encompasses a wide variety of actions and therefore “determining” can include calculating, computing, processing, deriving, investigating, looking up (e.g., looking up in a table, a database or another data structure), ascertaining and the like. Also, “determining” can include receiving (e.g., receiving information), accessing (e.g., accessing data in a memory) and the like. Also, “determining” can include resolving, selecting, choosing, establishing and the like.
Embodiments: Reference throughout the specification to “one embodiment,” “an embodiment,” “some embodiments,” “one aspect,” “an aspect,” “some aspects,” “some implementations,” “one implementation,” “an implementation,” or similar construction means that a particular component, feature, structure, method, or characteristic described in connection with the embodiment, aspect, or implementation is included in at least one embodiment and/or implementation of the claimed subject matter. Thus, the appearance of the phrases “in one embodiment” or “in an embodiment” or “in some embodiments” (or “aspects” or “implementations”) in various places throughout the specification are not necessarily all referring to the same embodiment and/or implementation. Furthermore, the particular features, structures, methods, or characteristics may be combined in any suitable manner in one or more embodiments or implementations.
Exemplary: “Exemplary” is used exclusively herein to mean “serving as an example, instance, or illustration.” Any embodiment described herein as “exemplary” is not necessarily to be construed as preferred or advantageous over other embodiments.
Flow diagram: Exemplary methods may be better appreciated with reference to flow diagrams or flow charts. While for purposes of simplicity of explanation, the illustrated methods are shown and described as a series of blocks, it is to be appreciated that the methods are not limited by the order of the blocks, as in different embodiments some blocks may occur in different orders and/or concurrently with other blocks from that shown and described. Moreover, less than all the illustrated blocks may be required to implement an exemplary method. In some examples, blocks may be combined, may be separated into multiple components, may employ additional blocks, and so on. In some examples, blocks may be implemented in logic. In other examples, processing blocks may represent functions and/or actions performed by functionally equivalent circuits (e.g., an analog circuit, a digital signal processor circuit, an application specific integrated circuit (ASIC)), or other logic device. Blocks may represent executable instructions that cause a computer, processor, and/or logic device to respond, to perform an action(s), to change states, and/or to make decisions. While the figures illustrate various actions occurring in serial, it is to be appreciated that in some examples various actions could occur concurrently, substantially in parallel, and/or at substantially different points in time. In some examples, methods may be implemented as processor executable instructions. Thus, a machine-readable medium may store processor executable instructions that if executed by a machine (e.g., processor) cause the machine to perform a method.
Full-physics: As used herein, the term “full-physics,” “full physics computational simulation,” or “full physics simulation” refers to a mathematical algorithm based on first principles that impact the pertinent response of the simulated system.
May: Note that the word “may” is used throughout this application in a permissive sense (i.e., having the potential to, being able to), not a mandatory sense (i.e., must).
Operatively connected and/or coupled: Operatively connected and/or coupled means directly or indirectly connected for transmitting or conducting information, force, energy, or matter.
Optimizing: The terms “optimal,” “optimizing,” “optimize,” “optimality,” “optimization” (as well as derivatives and other forms of those terms and linguistically related words and phrases), as used herein, are not intended to be limiting in the sense of requiring the present invention to find the best solution or to make the best decision. Although a mathematically optimal solution may in fact arrive at the best of all mathematically available possibilities, real-world embodiments of optimization routines, methods, models, and processes may work towards such a goal without ever actually achieving perfection. Accordingly, one of ordinary skill in the art having benefit of the present disclosure will appreciate that these terms, in the context of the scope of the present invention, are more general. The terms may describe one or more of: 1) working towards a solution which may be the best available solution, a preferred solution, or a solution that offers a specific benefit within a range of constraints; 2) continually improving; 3) refining; 4) searching for a high point or a maximum for an objective; 5) processing to reduce a penalty function; 6) seeking to maximize one or more factors in light of competing and/or cooperative interests in maximizing, minimizing, or otherwise controlling one or more other factors, etc.
Order of steps: It should also be understood that, unless clearly indicated to the contrary, in any methods claimed herein that include more than one step or act, the order of the steps or acts of the method is not necessarily limited to the order in which the steps or acts of the method are recited.
Preferred: “preferred” and “preferably” refer to embodiments of the invention that afford certain benefits, under certain circumstances. However, other embodiments may also be preferred, under the same or other circumstances. Furthermore, the recitation of one or more preferred embodiments does not imply that other embodiments are not useful, and is not intended to exclude other embodiments from the scope of the invention.
Ranges: Concentrations, dimensions, amounts, and other numerical data may be presented herein in a range format. It is to be understood that such range format is used merely for convenience and brevity and should be interpreted flexibly to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of about 1 to about 200 should be interpreted to include not only the explicitly recited limits of 1 and about 200, but also to include individual sizes such as 2, 3, 4, etc. and sub-ranges such as 10 to 50, 20 to 100, etc. Similarly, it should be understood that when numerical ranges are provided, such ranges are to be construed as providing literal support for claim limitations that only recite the lower value of the range as well as claims limitation that only recite the upper value of the range. For example, a disclosed numerical range of 10 to 100 provides literal support for a claim reciting “greater than 10” (with no upper bounds) and a claim reciting “less than 100” (with no lower bounds).
Description
Reference will now be made to exemplary embodiments and implementations. Alterations and further modifications of the inventive features described herein and additional applications of the principles of the invention as described herein, such as would occur to one skilled in the relevant art having possession of this disclosure, are to be considered within the scope of the invention. Further, before particular embodiments of the present invention are disclosed and described, it is to be understood that this invention is not limited to the particular process and materials disclosed herein as such may vary to some degree. Moreover, in the event that a particular aspect or feature is described in connection with a particular embodiment, such aspects and features may be found and/or implemented with other embodiments of the present invention where appropriate. Specific language may be used herein to describe the exemplary embodiments and implementations. It will nevertheless be understood that such descriptions, which may be specific to one or more embodiments or implementations, are intended to be illustrative only and for the purpose of describing one or more exemplary embodiments. Accordingly, no limitation of the scope of the invention is thereby intended, as the scope of the present invention will be defined only by the appended claims and equivalents thereof.
In the interest of clarity, not all features of an actual implementation are described in this disclosure. For example, some well-known features, principles, or concepts, are not described in detail to avoid obscuring the invention. It will be appreciated that in the development of any actual embodiment or implementation, numerous implementation-specific decisions may be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. For example, the specific details of an appropriate computing system for implementing methods of the present invention may vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.
The step of characterizing the reservoir potential 410 of a reservoir may be performed using a reservoir model to characterize the reservoir potential over space and time. As indicated above, reservoir potential may be considered to be the driving force moving fluids from the formation (i.e., reservoir) towards the well and represents the formation's native ability to transmit fluids. Accordingly, reservoir potential may vary over space depending on the nature of the formation and may vary over time as the reservoir is depleted. Some implementations may utilize one or more models where the reservoir is simulated in cooperation with a well that is modeled as a simple inlet/outlet disregarding complexities in well construction and operation, skin factors, variations in the formation that might be caused by the drilling and/or completion of an actual well, and other factors that might limit the actual production rate and/or ability of a well to receive the driven formation fluids. Accordingly, as described above, the reservoir potential may be considered to be the conventional reservoir potential modeled by reservoir engineers using conventional modeling tools.
As indicated, one or more reservoir models may be used to determine the reservoir potential, which models may be used alone or in conjunction with other models commonly used in the industry. Depending on the models used to characterize reservoir potential, the reservoir potential may be measured in units of pressure, flow rate, permeability, and/or some combination of the above. A variety of models of differing complexities may be used as the reservoir model. For example, complex reservoir models, such as commercially available reservoir simulators and/or proprietary reservoir simulators, may be used to characterize the reservoir potential over space and time. Additionally or alternatively, simpler models may provide sufficient characterizations of reservoir potential over space and time. Accordingly, models ranging from full-physics reservoir models, to full-field reservoir simulators, to engineering solutions, such as parametric models, simple material balance models, and experienced approximations, may be used in characterizing the reservoir potential 410. The complexity of the reservoir model selected may affect the computational intensity of the present methods and the robustness of the results of the present methods. In some aspects of the present methods, complex reservoir models can be implemented in an algorithm to provide robust and accurate results while minimizing the computational intensity.
Returning to
While the variety of factors that affects the near-well region is readily understood, the near-well region is not typically modeled in isolation. While the near-well region may be modeled in any suitable manner, the near-well model of the present methods is adapted to characterize the near-well capacity, at 412. The near-well capacity represents the capacity of the near-well region to flow fluids therethrough without triggering or initiating a negative production event, such as sand production, compaction, water production, etc. Due to the variety of factors that affect the near-well region and the multitude of manners in which a negative production event may be initiated, the near-well model used to characterize the near-well capacity, at 412, may be based at least in part on full-physics modeling of a simulated well accessing the reservoir. Additionally or alternatively, other modeling techniques may be used, such as engineering approximations, numerical simulations, etc. In any event, the near-well model characterizes the near-well region at a finer scale and is better able to account for spatial and temporal differences in the near-well formation and in the drilling, completion, production, and treatment operations. Accordingly, the near-well model is able to characterize the near-well capacity.
As seen in
With the technologies of the present disclosure, particularly the ability to distinctly characterize the near-well capacity and the effective production capacity, operators are able to determine an optimized well potential over space and time relative to the characterized effective production capacity, as illustrated in
The optimized well potential may be determined using a well model to consider the impact on the well potential of various drilling, completion, and/or production operations. Well models of a variety of configurations may be constructed to simulate the behavior of the well during production operations, the complexity of which may depend on the nature of the well. In some implementations, the well model may be selected from any commercially available well model. Additionally or alternatively, the well model may comprise engineering models of varying complexity, numerical simulations of varying complexity, approximations, etc. For example, operators may choose to consider a range of relevant factors that will affect the well potential of a given well. Exemplary factors include, but are not limited to, the depth and direction of the well, the completion architecture (cased or open hole), the perforation strategy (when cased), the presence of sand control equipment, inflow control equipment, etc.
While any one or more of these factors may be considered by a suitable well model, some implementations of the present methods may utilize a well model based at least in part on full-physics modeling of a simulated well accessing the reservoir. By utilizing full-physics modeling of the simulated well, processes that impact the well potential of the simulated well are modeled based on first principles. Full-physics modeling of simulated wells is an emerging technology that can be implemented in a variety of computational environments. The mathematical models constituting the full-physics models may vary from one implementation to another according to the particulars of a given well and/or the preferences and/or judgment of a given operator conducting the simulation. Full-physics models typically include mathematical relationships between two or more mathematical models of real-world conditions. Just as the selection of particular mathematical models may vary from one implementation to another, the mathematical relationships between such models may vary depending on conditions of the well being simulated and/or the preferences and/or judgment of the operator conducting the simulation. Accordingly, a variety of full-physics models may be used in determining the well potential of a simulated well accessing the reservoir.
While the well potential of a simulated well accessing the reservoir may be simulated over space and time using suitable well models and/or suitable full-physics well models, determining an optimized well potential relative to the effective production capacity enables the modeled well potential to be used in making decisions related to the operation of the well.
Implementations of the present method may be configured to present operators with multiple views similar to those of
As illustrated in
As will be recalled,
The illustration of
Additionally or alternatively, optimized well potentials may be determined numerically through relationships between the reservoir model(s), the near-well model(s), and the well model(s), through algorithms relating the models and/or the results and inputs of the models, or through other computational means. In some implementations, the at least one optimized well potential may be determined based at least in part on an objective function that considers at least one of a plurality of decision-making factors. As used herein, the term “objective function” refers to any equations, combination of equations, models, simulations, etc. that consider the characterized effective production capacity, the modeled well potential, and one more decision-making factors to determine the well potential, as a function of time and/or space, that best approaches one or more operational objectives. Exemplary decision-making factors include those factors commonly considered in decisions about well operations, including production rates over time, production rates at a given time, operations costs, operational risks, reducing down time, etc., and combinations of the same. Accordingly, a simplified objective function may be configured to identify an optimized well potential relative to effective production capacity based on a consideration of a single decision-making factor, such as cost of completion equipment options, in order to meet an objective of minimizing completion costs. A more robust objective function may be configured to consider more decision-making factors, particularly factors that affect the long-term producibility of the well and the reservoir. Objective functions within the scope of the present disclosure may be configured to take advantage of the full-physics modeling of the simulated well and the simulated near-well region to consider the impact of various decisions over the life of the well on both the well and the formation.
With continuing reference to
Once a well operating plan is defined for a well associated with a reservoir, the modeled well potential for the well over space and time can be determined utilizing the methods described herein. However, the present methods may also be implemented in efforts to determine or define a well operating plan that provides the optimized well potential determined through the methods described herein. Accordingly, once an optimized well potential is determined as a function of space and/or time, operating plan components can be identified that can be incorporated into a well operating plan to provide the optimized well potential. Exemplary well operating plan components that may be determined in step 418 include one or more of equipment 424 and methods 426. For example, it may be determined that incorporating a particular piece of equipment in a completion can provide the optimized well potential (such as sand control equipment, in-flow control equipment, etc.). Additionally or alternatively, it may be determined that certain treating operations, such as acidizing, fracturing, etc., may need to be designed and executed in a manner that differs from conventional wisdom. The conventional wisdom, as described above is to maximize the initial production rate. However, a comparison of the production rates over time using the methods described herein may reveal that a completion or treatment option having a lower initial production may result in greater total production over time, such as when the initial production rate drops quickly and further for a first option and declines more slowly and/or less severely for a second option. Other equipment or methods may be considered for use in a well operating plan as well.
Due to the multitude of available combinations of equipment and methods that can be utilized in a well, some implementations may result in multiple operating plan components that can be utilized to provide the optimized well potential. In such implementations, the well operators may be able to select well operating plan components and/or combinations of components from the assortment available to provide the optimized well potential. Additionally or alternatively, in some implementations the optimized well potential over space and time may implicitly determine a corresponding optimized well operating plan, such as when a limited set of operating plan components are available to obtain the optimized well potential.
As can be understood from the foregoing, the methods of
In the representative illustration, the data to be input into the systems and methods, such as data regarding the reservoir, the near-well region, and/or the well, are stored in data storage device 712. The system computer 710 may retrieve the appropriate data from the data storage device 712 to perform the operations and analyses described herein according to program instructions that correspond to the methods described herein. For example, the program instructions may be configured to simulate the well, the near-well region, and/or the reservoir to determine the optimized well potential. The program instructions may be written in any suitable computer programming language or combination of languages, such as C++, Java and the like. The program instructions may be stored in a computer-readable memory, such as program data storage device 714. The memory medium storing the program instructions may be of any conventional type used for the storage of computer programs, including hard disk drives, floppy disks, CD-ROMs and other optical media, magnetic tape, and the like.
While the program instructions and the input data can be stored on and processed by the system computer 710, the results of the methods described herein may be exported for use in developing one or more optimized well operating plans, such as indicated at step 432 in
According to the representative implementation of
With returning reference to
In some implementations, the methods of the present invention include utilizing a well model to determine the well potential of a well operating plan, such as the initial well operating plan, which well operating plan includes a plurality of decisions over the well's expected life or a period of the well's expected life, such as schematically illustrated at box 816.
In some implementations, the step of determining an optimized well potential is done without reference to particular decision options, such as available equipment or known methods, to provide a theoretical optimized well potential. In such implementations, the iteratively varied well decisions may be considered unconstrained. The well potential of various well operating plans may then be determined using the models described above and compared to the optimized well potential until an optimized well operating plan is identified. In some implementations, the unconstrained iterations of well decisions may identify an optimized well potential that is not readily attainable using conventional equipment and methods. Far from being a failure, such implementations provide opportunities to engineer and/or invent new equipment and methods to optimize well operating plans, which equipment and methods could be used in other implementations.
Additionally or alternatively, the iterations of well decisions may be limited to combinations of well decisions utilizing available methods and/or equipment. For example, a well operating plan utilizing available or known equipment and methods may be developed and a corresponding well potential determined and compared against the determined optimized well potential relative to the effective production capacity. This process may be repeated until a best match is found between the well potential of an available well operating plan and the determined optimized well potential.
Continuing with the schematic flow chart of
The step of determining one or more well operating plan components 818 may be substantially similar to the manner in which that step was described above in connection with
It should be noted that not every implementation will include the step of producing hydrocarbons from the well. For example, the present methods, whether as described in
With reference to FIGS. 5 and 9-11, various scenarios representing exemplary implementations of the present methods are illustrated in the schematic representative manner described above in connection with
While the well operating plan providing the well potential schematically illustrated in
As described above, the well potentials illustrated in
Still additionally, some implementations of the present methods may allow the operator to identify two or more potential well operating plans, such as an existing well operating plan and one or more proposed operating plans, such as various possible workover plans. The present methods may be utilized to determine the well potential for each of the identified potential operating plans. As described above in connection with
As may be understood from the foregoing description, some implementations of the present methods may result in the development of a system associated with the use of hydrocarbons, such as a well operatively connected to a reservoir. The well of the system includes at least one component selected based at least in part on a computerized simulation adapted to: 1) characterize effective production capacity of the reservoir over space and time based at least in part on the reservoir potential and the near-well capacity; 2) determine an optimized well potential over space and time relative to the characterized effective production capacity using a well model; and 3) determine at least one component that can be incorporated into a well operating plan to provide the optimized well potential in the well. For example, the at least one component selected based at least in part on the computerized simulation may be selected from at least one of equipment and methods, such as drilling methods, completion methods, production methods, treatment methods, completion equipment, production equipment, etc. In some implementations, the equipment determined to be incorporated into the well operating plan may be developed based at least in part on results of the computerized simulation. For example, customized or innovative equipment may be required to approximate the optimized well potential determined by the computerized system. The computerized simulation may be adapted to further utilize an objective function and/or user input to consider factors relevant to determining the optimized well potential, such as cost of equipment, operational risks, regulatory limitations, etc. Additionally or alternatively, the computerized simulation may determine the optimized well potential according to any one or more of the methods described above. For example, the computerized simulation may iteratively vary one or more well operating decisions, may compare distinct well operating plans, and/or may determine a theoretical physics-based optimum unconstrained by currently available methods and equipment.
Similarly, it should be understood from the foregoing that the present invention includes computerized systems adapted to perform one or more of the methods described above. More particularly, and as suggested by the description of
While the techniques of the present invention may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown by way of example. It should again be understood that the invention is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present invention includes all modifications, equivalents, and alternatives falling within the spirit and scope of the appended claims.
The present application claims the benefit under 35 U.S.C. 119(e) of U.S. Provisional Application No. 61/144,307, filed 13 Jan. 2009 and U.S. Provisional Application No. 61/287,019, filed 16 Dec. 2009, which are incorporated herein by reference in their entirety for all purposes.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US2010/020119 | 1/5/2010 | WO | 00 | 6/9/2011 |
| Number | Date | Country | |
|---|---|---|---|
| 61144307 | Jan 2009 | US | |
| 61287019 | Dec 2009 | US |
