DETAILED ACTION
This action is responsive to the claims filed on September 3, 2025. Claims 1-20 are under consideration.
Claims 1-20 are rejected under 35 USC 101.
Claims 1-2, 5-6, 9, and 19 are rejected under 35 USC 103 in view of Loe, Chang, and Chevron.
Claims 3-4 are rejected under 35 USC 103 in view of Loe, Chang, Chevron, and Majidi.
Claims 8, 12, 14, and 15 are rejected under 35 USC 103 in view of Loe, Chang, and Hommel.
Claims 10-11 are rejected under 35 USC 103 in view of Loe, Chang, Chevron, and Heathman.
Claim 13 is rejected under 35 USC 103 in view of Loe, Chang, Hommel, and Jebutu.
Claim 16 is rejected under 35 USC 103 in view of Loe, Chang, Hommel, and Li.
Claims 17-18 are rejected under 35 USC 103 in view of Loe, Chang, Hommel, Heathman, and Chevron
Claim 20 is rejected under 35 USC 103 in view of Loe, Chang, Chevron, Heathman, Jacqueline, and Concrete Rhino.
Response to Arguments/Amendments
Claim Objections: The Applicant’s amendments and arguments have been considered and have overcome the objections. The objections have been withdrawn.
35 USC 112(a) Rejections: The Applicant’s amendments and arguments have been considered and are persuasive. The prior rejections have been withdrawn.
35 USC 112(b) Rejections: The Applicant’s amendments and arguments have been considered and are persuasive. The prior rejections have been withdrawn.
35 USC 101 Rejections: The Applicant’s amendments and arguments have been considered but are not persuasive. The Applicant argues that claims 1-20 include “meaningful limitations” that transform the claims into patent eligible subject matter. Specifically, the Applicant points to steps of generating a fluid loss control treatment by particle type iteration, as allegedly recited in independent claims 1, 12, and 19, as allegedly being meaningful limitations that amount to an inventive step due to their non-conventional arrangement of conventional elements. The Applicant’s admission that the individual steps of the claim are conventional is acknowledged and appreciated. The Applicant is also correct that an unconventional arrangement of otherwise conventional elements can confer eligibility. However, at least some of the novel/inventive/non-conventional nature of the claim must come from the additional limitations themselves. Trying different particle types when some are less than successful is an iterative approach that has been used in fluid treatment since before oil workers relied on computers and automation to determine a fluid treatment. Considering multiple different particle types (e.g., considering an available catalog of treatments, as in the cited references). If the Applicant was interested in meaningfully iterating in a way that could be considered integrated into a practical application, it might help if the method begins with an existing fluid treatment process, there is an active/real-time “detection” of data that is determined to indicate that an existing particle is insufficient for a current fracture, that the determinations that now exist in the claim are used to determine a more effective solution, and there is a real-time, automated switching of the solution. As it stands, the wherein clause that pumps the solution into the wellbore is not automated, so it is organizing human activity, not an additional limitation. The claim does not include an active detection step. Also, the processing of the data is not particularly integrated with the pumping. The iteration between different solutions is done entirely as a consideration of different options, not by trial and error or any interaction with the real world. To this end, the combination of the elements are not unconventional, whether considered individually or in combination, do not integrate the abstract idea into a practical application, and certainly, by being conventional, do not present an inventive concept. Accordingly, the rejections are maintained.
35 USC 103 Rejections: The amendments and arguments have been considered and are not persuasive. The iteration of fluids and particle types is sufficiently broad to encompass trying a first solution with as first solution or particle type and then trying another when the first does not work. This is explicitly taught in Loe, the primary reference. Accordingly, the cited references still teach all of the features of the claims, and the rejections are maintained.
Claim Rejections - 35 USC § 101
35 U.S.C. 101 reads as follows:
Whoever invents or discovers any new and useful process, machine, manufacture, or composition of matter, or any new and useful improvement thereof, may obtain a patent therefor, subject to the conditions and requirements of this title.
Claims 1-20 are rejected under 35 U.S.C. 101 because the claims are directed to an abstract idea without significantly more.
Independent Claims
Claim 1 (Statutory Category – Process)
Step 2A – Prong 1: Judicial Exception Recited?
Yes, the claims recite a mental process and a mathematical concept, which are abstract ideas.
MPEP 2106.04(a)(2)(Ill): “Accordingly, the "mental processes" abstract idea grouping is defined as concepts performed in the human mind, and examples of mental processes include observations, evaluations, Judgments, and opinions. […] The courts do not distinguish between mental processes that are performed entirely in the human mind and mental processes that require a human to use a physical aid (e.g., pen and paper or a slide rule) to perform the claim limitation.”
MPEP 2106.04(a)(2)(I): “When determining whether a claim recites a mathematical concept (i.e., mathematical relationships, mathematical formulas or equations, and mathematical calculations), examiners should consider whether the claim recites a mathematical concept or merely limitations that are based on or involve a mathematical concept […] a mathematical concept need not be expressed in mathematical symbols, because "[w]ords used in a claim operating on data to solve a problem can serve the same purpose as a formula." In re Grams, 888 F.2d 835, 837 and n.1, 12 USPQ2d 1824, 1826 and n.1 (Fed. Cir. 1989). See, e.g., SAP America, Inc. v. InvestPic, LLC, 898 F.3d 1161, 1163, 127 USPQ2d 1597, 1599 (Fed. Cir. 2018) (holding that claims to a ‘‘series of mathematical calculations based on selected information’’ are directed to abstract ideas); Digitech Image Techs., LLC v. Elecs. for Imaging, Inc., 758 F.3d 1344, 1350, 111 USPQ2d 1717, 1721 (Fed. Cir. 2014) (holding that claims to a ‘‘process of organizing information through mathematical correlations’’ are directed to an abstract idea).
MPEP 2106.04(a)(2)(I)(A): “Mathematical Relationships. A mathematical relationship is a relationship between variables or numbers. A mathematical relationship may be expressed in words or using mathematical symbols.”
Claim 1 recites (claim features in italics, paragraph references are to the Applicant’s specification):
A […] method of designing a wellbore fluid treatment, comprising:
determining, by the design process, a fluid loss rate from the at least one dataset; (Math calculations in textual form, using math equations/relationships of the particle model, wherein this is recited in such generality a person is readily able to do a mental evaluation of the math using pen, paper, and/or a calculator: [0048] “The formation fracture model 424 can calculate the loss rate based on mathematical models of each type of fracture and generate a probability of the fluid loss rate being a resultant of each type of fracture.” [0051] “Below is another example equation that may be used to determine the loss rate.” Also, see paragraphs [0053]-[0055])
determining, by the design process, a fracture location within the wellbore; (Mental evaluation: [0025] “In some embodiments, the wellbore hydraulics model may be a drilling fluids model. The drilling fluids model may determine a circulating pressure, fluid loss rate, a hole cleaning efficiency, a location of a low pressure zone, or combinations thereof.” [0047] “The design process 124 can input the datasets as input values 412 into one or more models 126, for example, the wellbore hydraulics model 414. The wellbore hydraulics model 414 can determine output values 416 comprising a fluid loss mechanism, a fluid loss rate, a fluid rheology, a wellbore geometry and trajectory, formation properties, or combinations thereof for at least one low pressure zone, e.g., formation 314, within the wellbore 6.” [0048] “At step 420, the input values 422 of the second model, e.g., model 424, can include the output values 416 of the first model, e.g., model 414. The design process 124 can transfer the output values 416 from the wellbore hydraulics model 414 to the formation fracture model 424 as input values 422. The input values 422 may include the fluid loss mechanism, a differential pressure, fluid density and rheology, and the material properties of the formation, e.g., formation 314. The formation fracture model 424 can determine a probability of the fracture, e.g., fracture 334 of formation 314, being one of three types of fractures: a natural fracture, an induced fracture, or a highly permeable zone. The formation fracture model 424 can calculate the loss rate based on mathematical models of each type of fracture and generate a probability of the fluid loss rate being a resultant of each type of fracture.” See also Equations 1-2.)
generating a fluid loss control treatment by particle type iteration comprising: selecting a first particle type from an inventory of particle types; (Mental Process, Mathematical Concept, Abstract Ideas – Making a selection of an element from a rubric is practically performable in the mind or with the aid of pen and paper. This is an abstract idea.)
determining, by a particle model, a particle type to form an interface with a filter property at the fracture location, wherein a fracture geometry is an input into the particle model, wherein the filter property achieves an operational objective, and wherein the filter property is a porosity value, a permeability value, or combinations thereof; (Math calculations in textual form, using math equations/relationships of the particle model, wherein this is recited in such generality a person is readily able to do a mental evaluation of the math using pen, paper, and/or a calculator: [0061] “At step 430, the input values 432 of the third model, e.g., model 434, can include the output values 426 of the second model, e.g., model 424. The design process 124 can transfer the output values 426 from the formation fracture model 424 to the particle model 434 as input values 432. The input values 432 may include the fracture type, the fracture geometry, an inventory of particles, a delivery fluid density and rheology, a concentration of particles, or combinations thereof. The particle model 434 can determine a probability of placement of the particle type within the throat of the fracture, also referred to as jamming the fracture, e.g., fracture 334 of formation 314, to form an interface along the surface and into the fracture. The particle model 434 can calculate the probability of placement of the particle type within the throat, e.g., jamming, based on a mathematical model of the relationship of particle size, particle geometry, and distribution along the fracture geometry depending on the type of fracture.” [0066] “With a known fracture geometry, from output values 426 of step 420, these equations may be used in the model 434, for example, to determine the probability of jamming along the geometry of the fracture and the resultant permeability characteristics. However, these example calculations are only representative” – The recited “particle model” is a placeholder for equations.)
determining whether the first value of the filter property exceeds a threshold; (Mental Process, Mathematical Concept, Abstract Ideas – Comparing numbers or qualitative metrics is practically performable in the mind or with the aid of pen and paper. Also, comparing numbers is rudimentary math, a mathematical concept. These are abstract ideas.)
selecting a second particle type from the inventory of particle types, in response to determining that the first value of the filter property does not exceed the threshold; (Mental Process, Mathematical Concept, Abstract Ideas – Making a selection of an element based on the simple number comparison from a rubric is practically performable in the mind or with the aid of pen and paper. These are abstract ideas)
determining, by the particle model, a second value of the filter property at the fracture location resulting from treatment with the second particle type; (Mental Process, Abstract Idea – Determining a value from a rubric is practically performable in the mind or with the aid of pen and paper. These are abstract ideas)
determining whether the second value of the filter property exceeds the threshold; and (Mental Process, Mathematical Concept, Abstract Ideas – Comparing numbers or qualitative metrics is practically performable in the mind or with the aid of pen and paper. Also, comparing numbers is rudimentary math, a mathematical concept. These are abstract ideas.)
generating, by the design process, the fluid loss control treatment based on the second particle type and a concentration of the second particle type to form at the interface, in response to determining that the second value of the filter property exceeds a threshold, (Mental evaluation: [0004] “In fluid loss control treatments, the composition can include a LCM particle and a carrier fluid to suspend and transport the LCM particle to the target location, e.g., lost circulation zone. The type of LCM material can be selected based on the formation type, specific to an oil field, or specified by a customer. The fluid properties, such as density, of the carrier fluid may be tailored to the specific gravity of the LCM particle. The compatibility of the carrier fluid to the formation properties may limit the fluid properties of the carrier fluid. The effectiveness of the fluid loss control treatment can depend on selecting an effective LCM treatment based on the type of low pressure zone. A method of designing a well treatment with a LCM particle and carrier fluid compatible with the type of low pressure zone is desirable.” [0069] “A fluid loss event may be anticipated from a historical database of existing wellsites. At least one fluid loss control treatments can be designed based the drilling dataset from one or more offset wells within the same field. A request may be received from a customer device 136 for a fluid loss control treatment for a new wellsite within the same field as at least one offset wellsite. Turning now to FIG. 8, a method 800 of designing a fluid loss control treatment from offset well data is illustrated as a logic block diagram. The design process 124 of FIG. 3 may utilize at least one model 126 to generate a fluid loss control treatment for a known low pressure zone, e.g., fracture 336 of FIG. 3. At step 810, the design process 124 may retrieve a drilling dataset of an offset well from a historical database 128 located on storage computer 114. As previously described, the drilling dataset may include the daily drilling log, the mud log, the mud logging report, a sensor dataset from the fluid system, the lifting mechanism, the rotation mechanism, the wellhead, the BHA 10, or combinations thereof. The design process 124 may retrieve the drilling dataset from the historical database 128, the storage computer 114, the communication device 118, the remote wellsite 116, the customer device 136, the computer system 122, a virtual computer within the 5G network, or combinations thereof.”)
The determining steps, selecting step and generating step are evaluations, which are mental processes a petroleum engineer could conduct using pen, paper, and/or a calculator. (See Examples 43 and 45 of the October 2019 Examples 43-46, Specifically, example 45, claim 1). First, the determining […] a fluid loss rate step is a mental process, but it is done a computer, given the generality recited in how this is done(See MPEP 2106.04(a)(2)(III)(A) for Electric Power Group), e.g., an engineer, observing a chart of measured data on paper of the display on a computer, and mentally making a simple calculation using physical aids, such as pen, paper, and/or a calculator. Second, the determining […] a fracture location step is sufficiently broad to include, but for the generic computer implementation, an engineer observing a visual representation of the zones around the wellbore, colored based on pressure levels, and mentally judging the fracture location (See [0002] of the Applicant’s specification). Third, the determining […] a particle type to form an interface is sufficiently broad to include, but for the generic computer implementation, a petroleum engineer considering the nature of the determined fracture and particle sizes useful for that fracture. Fourth, the generating, by a design process, a fluid loss control treatment step is sufficiently broad to include an engineer determining a mixture of particles and fluids of a fluid loss control treatment on a piece of paper.
Further, the evaluations of the determining, by the design process, a fluid loss rate and determining, by a particle model, a particle type steps are mathematical calculations in textual form, which are mathematical concepts (See paragraphs [0049]-[0067] and equations 1-14).
Mental processes and mathematical concepts are abstract ideas.
Claim 1 recites an abstract idea.
Step 2A – Prong 2: Integrated into a Practical Application?
No.
MPEP 2106.04(d): “[A]fter determining that a claim recites a judicial exception in Step 2A Prong One, examiners should evaluate whether the claim as a whole integrates the recited judicial exception into a practical application of the exception in Step 2A Prong Two. A claim that integrates a judicial exception into a practical application will apply, rely on, or use the judicial exception in a manner that imposes a meaningful limit on the judicial exception, such that the claim is more than a drafting effort designed to monopolize the judicial exception. Whether or not a claim integrates a judicial exception into a practical application is evaluated using the considerations set forth in subsection I below, in accordance with the procedure described below in subsection II.”
MPEP 2106.05(f) Mere Instructions To Apply An Exception: “Another consideration when determining whether a claim integrates a judicial exception into a practical application in Step 2A Prong Two or recites significantly more than a judicial exception in Step 2B is whether the additional elements amount to […] more than a recitation of the words "apply it" (or an equivalent), such as mere instructions to implement an abstract idea on a computer, examiners should explain why they do not meaningfully limit the claim in an eligibility rejection. For example, an examiner could explain that implementing an abstract idea on a generic computer, does not integrate the abstract idea into a practical application in Step 2A Prong Two or add significantly more in Step 2B.
MPEP 2106.05(g): “Another consideration when determining whether a claim integrates the judicial exception into a practical application in Step 2A Prong Two or recites significantly more in Step 2B is whether the additional elements add more than insignificant extra-solution activity to the judicial exception. The term "extra-solution activity" can be understood as activities incidental to the primary process or product that are merely a nominal or tangential addition to the claim. Extra-solution activity includes both pre-solution and post-solution activity. An example of pre-solution activity is a step of gathering data for use in a claimed process, e.g., a step of obtaining information about credit card transactions, which is recited as part of a claimed process of analyzing and manipulating the gathered information by a series of steps in order to detect whether the transactions were fraudulent.”
The additional limitations:
retrieving, by a design process executing on a processor, at least one dataset of a servicing operation at a wellbore;
The retrieving step merely gathers existing information (a dataset of a servicing operation at a wellbore) for evaluation. Mere data gathering is insignificant extra solution activity under MPEP 2106.05(g). Under Mere Data Gathering, an analogous example is provided: “iv. Obtaining information about transactions using the Internet to verify credit card transactions, CyberSource v. Retail Decisions, Inc., 654 F.3d 1366, 1375, 99 USPQ2d 1690, 1694 (Fed. Cir. 2011).” Under MPEP 2106.05(g), receiving data for evaluation is not significant in meaningfully limiting the invention, and the receiving of the data is necessary to the evaluations and mathematical operations of the claim. Under MPEP 2106.05(g). The retrieving step adds nothing more than insignificant extra solution activity, so it does not integrate the abstract idea into a practical application in Step 2A Prong Two.
Should it be found that the generating step is an additional limitation, rather than an element of the abstract idea, the generating step is token post-solution activity under MPEP 2106.05(g) and/or mere instructions to “apply it” under MPEP 2106.05(f). Also, the generating step merely limits the claim to a particular field of preparing a fluid loss control treatment under 2106.05(h). Therefore, the generating step fails to integrate the abstract idea into a practical application at Step 2A, Prong 2.
[…] computer-implemented […]
[…] particle model […]
The computer implementation is a recitation of a general purpose computer with no specific configurations to execute the claimed method. As such, the computer implementation implements the recited abstract idea on a generic computer, and, under MPEP 2106.05(f) does not integrate the abstract idea into a practical application in Step 2A, Prong Two.
wherein particle-laden fluid is pumped into a wellbore according to the generated fluid loss control treatment.
This is an example of insignificant extra-solution activity analogous to the examples in MPEP 2106.05(g): i. Cutting hair after first determining the hair style, In re Brown, 645 Fed. App'x 1014, 1016-1017 (Fed. Cir. 2016) (non-precedential). Once you have designed a fluid control treatment, what other application is there for it than generally using it as a fluid control treatment in a wellbore. Because the wherein clause is insignificant extra-solution activity, under MPEP 2106.05(g), the wherein clause fails to integrate the abstract idea into a practical application.
Therefore, there are no additional limitations in claim 1 that integrate the abstract idea into a practical application under Step 2A, Prong Two.
Claim 1 does not integrate the abstract idea into a practical application and is directed to the abstract idea.
Step 2B: Claim provides an Inventive Concept?
No.
MPEP 2106.05(I) “An inventive concept "cannot be furnished by the unpatentable law of nature (or natural phenomenon or abstract idea) itself. […] Instead, an "inventive concept" is furnished by an element or combination of elements that is recited in the claim in addition to (beyond) the judicial exception, and is sufficient to ensure that the claim, as a whole, amounts to significantly more than the judicial exception itself.”
MPEP 2106.05(f) Mere Instructions To Apply An Exception: “[I]mplementing an abstract idea on a generic computer, does not integrate the abstract idea into a practical application in Step 2A Prong Two or add significantly more in Step 2B.
MPEP 2106.05(d)(II)(i): “The courts have recognized the following computer functions as well‐understood, routine, and conventional functions when they are claimed in a merely generic manner (e.g., at a high level of generality) or as insignificant extra-solution activity. […] i. Receiving or transmitting data over a network, e.g., using the Internet to gather data […] iii. iii. Electronic recordkeeping […] iv. Storing and retrieving information in memory”
MPEP 2106.05(g): “As explained by the Supreme Court, the addition of insignificant extra-solution activity does not amount to an inventive concept, particularly when the activity is well-understood or conventional. Parker v. Flook, 437 U.S. 584, 588-89, 198 USPQ 193, 196 (1978).”
The additional limitations:
retrieving, by a design process executing on a processor, at least one dataset of a servicing operation at a wellbore;
This retrieving step is storing and retrieving information from memory and also indicative of sending or reciting data, so it is analogous to the examples cited in MPEP 2106.05(d)(II)(i) and (iii), representing well-understood, routine, and conventional functions. This receiving step is also akin to the limitation in Electric Power Group (See 2106.04(a)(2)(III)(D) “• A wide-area real-time performance monitoring system for monitoring and assessing dynamic stability of an electric power grid – Electric Power Group, 830 F.3d at 1351 and n.1, 119 USPQ2d at 1740 and n.1;” representing well-understood, routine, and conventional functions.
Because the additional limitation of the retrieving step is insignificant extra-solution activity (as illustrated under Step 2A Prong 2) and a well-understood, routine, and conventional function, the retrieving step fails to provide the abstract idea with significantly more to render the combination of the additional limitations with the other claim elements an inventive concept, under MPEP 2106.05(f) and MPEP 2106.05(g) respectively.
Should it be found that the generating step is an additional limitation, rather than an element of the abstract idea, the generating step is token post-solution activity under MPEP 2106.05(g) and/or mere instructions to “apply it” under MPEP 2106.05(f). Further, the generating step is well-recognized, routine, and conventional activity akin to the example in MPEP 2106.05(d)(II) “Below are examples of other types of activity that the courts have found to be well-understood, routine, conventional activity when they are claimed in a merely generic manner (e.g., at a high level of generality) or as insignificant extra-solution activity: […] v. Determining an estimated outcome and setting a price, OIP Techs., 788 F.3d at 1362-63, 115 USPQ2d at 1092-93.“ Also, the generating step merely limits the claim to a particular field of preparing a fluid loss control treatment under 2106.05(h). Therefore, the generating step fails to combine with the other elements to provide significantly more than the abstract idea that would confer an inventive concept at step 2B.
[…] computer-implemented […]
[…] particle model […]
The computer implementation is a recitation of a general purpose computer with no specific configurations to execute the claimed method. As such, the computer implementation implements the recited abstract idea on a generic computer, and, under MPEP 2106.05(f) fails to combine with the other elements of the claim to provide significantly more, and, therefore, fails to confer an inventive concept.
wherein particle-laden fluid is pumped into a wellbore according to the generated fluid loss control treatment.
This is an example of well-understood, routine, conventional (WURC) activity. Here is evidence: API Standard 65, Part 2, Second Edition, Dec. 2010, "Isolating Potential Flow Zones During Well Construction",§ 5.7.4 ,i 1, § 7.3 ,i 2, Appendix B, § B.2.4, the bulleted list for the cementing plan including "pump rates"; also§ 5.6.4 ,i 2: "Computer based thermal modeling programs may be used to develop cementing testing temperatures. Such programs require input information such as static temperature, formation and well fluid thermal characteristics, rheologies, estimated job volumes, planned pump rates and well geometry. The predictions generated by thermal modeling programs may vary significantly; operators may consider employing more than one thermal model to arrive at a cement test temperature schedule", and§ 5.6.5.5: "Some computer programs may be used to determine the type and volume of spacers to be pumped for drilling fluid removal and predict the degree of fluid (cement, spacer, drilling fluid) intermixing that may occur during placement.",§ 5.9.5 ,i,i 1-2 incl.: "Pumping the cement job with the designed pump rates is important but density control should not be sacrificed to obtain a planned rate." Because the wherein clause is WURC under MPEP 2106.05(d) and insignificant extra-solution activity under MPEP 2106.05(g), the wherein clause fails to combine with the other elements of the claims to provide significantly more than the abstract idea that would confer an inventive concept.
Therefore, there are no additional limitations in claim 1 that, in combination with other elements of the claim, furnish claim 1 with an inventive concept such that claim 1, as a whole, amounts to significantly more than the bolded abstract idea under Step 2B.
Claim 1 is ineligible.
Claim 12 (Statutory Category – Process)
Step 2A – Prong 1: Judicial Exception Recited?
Yes, the claims recite a mental process and a mathematical concept, which are abstract ideas.
See the MPEP sections cited in the eligibility analysis of claim 1.
Claim 12 recites (claim features in italics, paragraph references are to the Applicant’s specification):
A […] method of designing a fluid loss control treatment with real-time pumping data, comprising: determining, […] a fluid loss rate from the at least one real-time dataset; (Mental evaluation of mathematical calculations in textual form: [0047] “The design process 124 can input the datasets as input values 412 into one or more models 126, for example, the wellbore hydraulics model 414. The wellbore hydraulics model 414 can determine output values” [0048] “The formation fracture model 424 can calculate the loss rate based on mathematical models of each type of fracture and generate a probability of the fluid loss rate being a resultant of each type of fracture.” [0051] “Below is another example equation that may be used to determine the loss rate” Also, note that the real-time features is akin to the real-time feature presented in Electric Power Group and did not render the claim eligible.)
determining, by the design process, a fracture location within the wellbore; (Mental Process, Abstract Idea: The determination of a location of a fracture was performed prior to the use of automation based on the data of the wellsite. Therefore, it is practically performable in the mind or with the aid of pen and paper. Therefore, it is a mental process, an abstract idea.)
generating a fluid loss control treatment by particle type iteration, comprising: selecting a first particle type from an inventory of particle types; (Mental Process, Abstract Idea: The generation of fluid treatments and selection of particles therefore, were performed prior to the use of automation based on the data of the wellsite. Therefore, it is practically performable in the mind or with the aid of pen and paper. Therefore, it is a mental process, an abstract idea.)
determining, by a particle model, a first value of a filter property at the fracture location resulting of treatment with the first particle type, wherein the filter property is a porosity value, a permeability value, or combinations thereof; (Mental Process, Abstract Idea: The determining a value of a filter property, such as based on a rubric was performed before automation of fluid treatment. Therefore, it is practically performable in the mind or with the aid of pen and paper. Therefore, it is a mental process, an abstract idea.)
determining whether the first value of the filter property exceeds a threshold; (Mental Process, Mathematical Concept, Abstract Ideas – Comparing numbers or qualitative metrics is practically performable in the mind or with the aid of pen and paper. Also, comparing numbers is rudimentary math, a mathematical concept. These are abstract ideas.)
selecting a second particle type from the inventory of particle types, in response to determining that the first value of the filter property does not exceed the threshold; (Mental Process, Mathematical Concept, Abstract Ideas – Making a selection of an element based on the simple number comparison from a rubric is practically performable in the mind or with the aid of pen and paper. These are abstract ideas)
determining, by the particle model, a second value of the filter property at the fracture location resulting from treatment with the second particle type; (Mental Process, Abstract Idea – Determining a value from a rubric is practically performable in the mind or with the aid of pen and paper. These are abstract ideas)
determining whether the second value of the filter property exceeds the threshold; and (Mental Process, Mathematical Concept, Abstract Ideas – Comparing numbers or qualitative metrics is practically performable in the mind or with the aid of pen and paper. Also, comparing numbers is rudimentary math, a mathematical concept. These are abstract ideas.)
generating, by the design process, a fluid loss control treatment based on the second particle type and a concentration of the second particle type to form at the interface, in response to determining that the second value of the filter exceeds the threshold, (Mental evaluation: [0004] “In fluid loss control treatments, the composition can include a LCM particle and a carrier fluid to suspend and transport the LCM particle to the target location, e.g., lost circulation zone. The type of LCM material can be selected based on the formation type, specific to an oil field, or specified by a customer. The fluid properties, such as density, of the carrier fluid may be tailored to the specific gravity of the LCM particle. The compatibility of the carrier fluid to the formation properties may limit the fluid properties of the carrier fluid. The effectiveness of the fluid loss control treatment can depend on selecting an effective LCM treatment based on the type of low pressure zone. A method of designing a well treatment with a LCM particle and carrier fluid compatible with the type of low pressure zone is desirable.” [0069] “A fluid loss event may be anticipated from a historical database of existing wellsites. At least one fluid loss control treatments can be designed based the drilling dataset from one or more offset wells within the same field. A request may be received from a customer device 136 for a fluid loss control treatment for a new wellsite within the same field as at least one offset wellsite. Turning now to FIG. 8, a method 800 of designing a fluid loss control treatment from offset well data is illustrated as a logic block diagram. The design process 124 of FIG. 3 may utilize at least one model 126 to generate a fluid loss control treatment for a known low pressure zone, e.g., fracture 336 of FIG. 3. At step 810, the design process 124 may retrieve a drilling dataset of an offset well from a historical database 128 located on storage computer 114. As previously described, the drilling dataset may include the daily drilling log, the mud log, the mud logging report, a sensor dataset from the fluid system, the lifting mechanism, the rotation mechanism, the wellhead, the BHA 10, or combinations thereof. The design process 124 may retrieve the drilling dataset from the historical database 128, the storage computer 114, the communication device 118, the remote wellsite 116, the customer device 136, the computer system 122, a virtual computer within the 5G network, or combinations thereof.” – People of ordinary skill in the art have been generating fluid loss control treatments with these methods since before automation.)
These steps are evaluations, which are mental processes a petroleum engineer could conduct using pen, paper, and/or a calculator. (See Examples 43 and 45 of the October 2019 Examples 43-46). First, the determining […] a fluid loss rate step is a sufficiently broad, but for the generic computer implementation, to include a petroleum engineer using a simple equation to determine a fluid loss rate. Second, the determining […] a low pressure zone step is sufficiently broad to include, but for the generic computer implementation, an engineer observing a visual representation of the zones around the wellbore, colored based on pressure levels, and mentally judging the fracture location (See [0002] of the Applicant’s specification). Third, the determining, by a particle model, a fluid loss control treatment is sufficiently broad to include, but for the generic computer implementation, a petroleum engineer considering the nature of the determined fracture and particle sizes useful for that fracture. Fourth, the generating, by the design process, a fluid loss control treatment step is sufficiently broad to include an engineer determining a mixture of particles and fluids of a fluid loss control treatment on a piece of paper.
Further, the evaluations of the determining, […] a fluid loss rate and determining, by a particle model, a particle type and determining, by a particle model, a fluid loss control treatment steps are mathematical calculations in textual form, which are mathematical concepts (See paragraphs [0049]-[0067] and equations 1-14).
Claim 12 recites an abstract idea.
Step 2A – Prong 2: Integrated into a Practical Application?
No.
See the MPEP sections cited in the eligibility analysis of claim 1.
The additional limitations:
receiving, by a design process executing on a processor, at least one real-time dataset associated with a pumping equipment fluidically connected to a wellbore, wherein the at least one real-time dataset comprises a dataset selected from the group consisting of drilling equipment dataset, bottom hole assembly (BHA) dataset, fluid system dataset, or combination thereof;
The receiving step merely gathers existing information (a dataset of a servicing operation at a wellbore) for evaluation. Mere data gathering is insignificant extra solution activity under MPEP 2106.05(g). Under Mere Data Gathering, an analogous example is provided: “iv. Obtaining information about transactions using the Internet to verify credit card transactions, CyberSource v. Retail Decisions, Inc., 654 F.3d 1366, 1375, 99 USPQ2d 1690, 1694 (Fed. Cir. 2011).” Under MPEP 2106.05(g), receiving data for evaluation is not significant in meaningfully limiting the invention, and the receiving of the data is necessary to the evaluations and mathematical operations of the claim. Under MPEP 2106.05(g). The receiving step adds nothing more than insignificant extra solution activity, so it does not integrate the abstract idea into a practical application in Step 2A Prong Two.
Should it be found that the generating step is an additional limitation, rather than an element of the abstract idea, the generating step is token post-solution activity under MPEP 2106.05(g) and/or mere instructions to “apply it” under MPEP 2106.05(f). Also, the generating step merely limits the claim to a particular field of preparing a fluid loss control treatment under 2106.05(h). Therefore, the generating step fails to integrate the abstract idea into a practical application at Step 2A, Prong 2.
[…] computer-implemented […]
[…] executing on a processor […]
[…] by the processor […]
[…] particle model […]
The computer implementation is a recitation of a general purpose computer with no specific configurations to execute the claimed method. As such, the computer implementation implements the recited abstract idea on a generic computer, and, under MPEP 2106.05(f) does not integrate the abstract idea into a practical application in Step 2A Prong Two.
wherein particle-laden fluid is pumped into a wellbore according to the generated fluid loss control treatment.
This is an example of insignificant extra-solution activity analogous to the examples in MPEP 2106.05(g): i. Cutting hair after first determining the hair style, In re Brown, 645 Fed. App'x 1014, 1016-1017 (Fed. Cir. 2016) (non-precedential). Once you have designed a fluid control treatment, what other application is there for it than generally using it as a fluid control treatment in a wellbore. Because the wherein clause is insignificant extra-solution activity, under MPEP 2106.05(g), the wherein clause fails to integrate the abstract idea into a practical application.
Therefore, there are no additional limitations in claim 12 that integrate the abstract idea into a practical application under Step 2A, Prong 2.
Claim 12 does not integrate the abstract idea into a practical application and is directed to the abstract idea.
Step 2B: Claim provides an Inventive Concept?
No.
See the MPEP sections cited in the eligibility analysis of claim 1.
The additional limitations:
receiving, by a design process, at least one real-time dataset associated with a pumping equipment fluidically connected to a wellbore, wherein the at least one real-time dataset comprises a dataset selected from the group consisting of drilling equipment dataset, bottom hole assembly (BHA) dataset, fluid system dataset, or combination thereof;
This receiving step is storing and retrieving information from memory and also indicative of sending or reciting data, so it is analogous to the examples cited in MPEP 2106.05(d)(II)(i) and (iii). This receiving step is also akin to the limitation in Electric Power Group (See 2106.04(a)(2)(III)(D) “A wide-area real-time performance monitoring system for monitoring and assessing dynamic stability of an electric power grid – Electric Power Group, 830 F.3d at 1351 and n.1, 119 USPQ2d at 1740 and n.1;” representing well-understood, routine, and conventional functions.
The association “with a pumping equipment fluidically connected to a wellbore, wherein the at least one real-time dataset comprises a dataset selected from the group consisting of drilling equipment dataset, bottom hole assembly (BHA) dataset, fluid system dataset, or combination thereof” merely generally inks the features of the claim to a field of use in the drilling industry under MPEP 2106.05(h) for example, as shown in the example from Electric Power Group “vi. Limiting the abstract idea of collecting information, analyzing it, and displaying certain results of the collection and analysis to data related to the electric power grid, because limiting application of the abstract idea to power-grid monitoring is simply an attempt to limit the use of the abstract idea to a particular technological environment, Electric Power Group, LLC v. Alstom S.A., 830 F.3d 1350, 1354, 119 USPQ2d 1739, 1742 (Fed. Cir. 2016);”)
Because the additional limitation of the receiving step is insignificant extra-solution activity (as illustrated under Step 2A Prong 2) and a well-understood, routine, and conventional function, the receiving step fails to provide the abstract idea with significantly more to render the combination of the additional limitations with the other claim elements an inventive concept, under MPEP 2106.05(f) and MPEP 2106.05(g) respectively.
Should it be found that the generating step is an additional limitation, rather than an element of the abstract idea, the generating step is token post-solution activity under MPEP 2106.05(g) and/or mere instructions to “apply it” under MPEP 2106.05(f). Further, the generating step is well-recognized, routine, and conventional activity akin to the example in MPEP 2106.05(d)(II) “Below are examples of other types of activity that the courts have found to be well-understood, routine, conventional activity when they are claimed in a merely generic manner (e.g., at a high level of generality) or as insignificant extra-solution activity: […] v. Determining an estimated outcome and setting a price, OIP Techs., 788 F.3d at 1362-63, 115 USPQ2d at 1092-93.“ Also, the generating step merely limits the claim to a particular field of preparing a fluid loss control treatment under 2106.05(h). Therefore, the generating step fails to combine with the other elements to provide significantly more than the abstract idea that would confer an inventive concept at step 2B.
[…] computer-implemented […]
[…] executing on a processor […]
[…] by the processor […]
[…] particle model […]
The computer implementation is a recitation of a general purpose computer with no specific configurations to execute the claimed method. As such, the computer implementation implements the recited abstract idea on a generic computer, and, under MPEP 2106.05(f) fails to combine with the other elements of the claim to provide significantly more, and, therefore, fails to confer an inventive concept.
wherein particle-laden fluid is pumped into a wellbore according to the generated fluid loss control treatment.
This is an example of well-understood, routine, conventional (WURC) activity. Here is evidence: API Standard 65, Part 2, Second Edition, Dec. 2010, "Isolating Potential Flow Zones During Well Construction",§ 5.7.4 ,i 1, § 7.3 ,i 2, Appendix B, § B.2.4, the bulleted list for the cementing plan including "pump rates"; also§ 5.6.4 ,i 2: "Computer based thermal modeling programs may be used to develop cementing testing temperatures. Such programs require input information such as static temperature, formation and well fluid thermal characteristics, rheologies, estimated job volumes, planned pump rates and well geometry. The predictions generated by thermal modeling programs may vary significantly; operators may consider employing more than one thermal model to arrive at a cement test temperature schedule", and§ 5.6.5.5: "Some computer programs may be used to determine the type and volume of spacers to be pumped for drilling fluid removal and predict the degree of fluid (cement, spacer, drilling fluid) intermixing that may occur during placement.",§ 5.9.5 ,i,i 1-2 incl.: "Pumping the cement job with the designed pump rates is important but density control should not be sacrificed to obtain a planned rate." Because the wherein clause is WURC under MPEP 2106.05(d) and insignificant extra-solution activity under MPEP 2106.05(g), the wherein clause fails to combine with the other elements of the claims to provide significantly more than the abstract idea that would confer an inventive concept.
Therefore, there are no additional limitations in claim 12 that, in combination with other elements of the claim, furnish claim 12 with an inventive concept to ensure that claim 12, as a whole, amounts to significantly more than the bolded abstract idea under Step 2B.
Claim 12 is ineligible.
Claim 19 (Statutory Category – Process)
Step 2A – Prong 1: Judicial Exception Recited?
Yes, the claims recite a mental process and a mathematical operation, which are abstract ideas.
See the MPEP sections cited in the eligibility analysis of claim 1.
Claim 19 recites (claim features in italics, paragraph references are to the Applicant’s specification):
A […] method of designing a fluid loss control treatment, comprising:
determining, by a hydraulic fluid model, a fluid loss rate by inputting the drilling dataset into the hydraulic fluid model; (Mental evaluation of mathematical calculations in textual form: [0047] “The design process 124 can input the datasets as input values 412 into one or more models 126, for example, the wellbore hydraulics model 414. The wellbore hydraulics model 414 can determine output values” [0048] “The formation fracture model 424 can calculate the loss rate based on mathematical models of each type of fracture and generate a probability of the fluid loss rate being a resultant of each type of fracture.” [0051] “Below is another example equation that may be used to determine the loss rate” See also paragraphs [0053]-[0055])
determining, by the design process, a fracture location within the wellbore; (Mental Process, Abstract Idea: The determination of a location of a fracture was performed prior to the use of automation based on the data of the wellsite. Therefore, it is practically performable in the mind or with the aid of pen and paper. Therefore, it is a mental process, an abstract idea.)
generating a fluid loss control treatment by particle type iteration, comprising; selecting a first particle type from an inventory of particle types; (Mental Process, Abstract Idea: The generation of fluid treatments and selection of particles therefore, were performed prior to the use of automation based on the data of the wellsite. Therefore, it is practically performable in the mind or with the aid of pen and paper. Therefore, it is a mental process, an abstract idea.)
determining, by a particle model, a first value of a filter property at the fracture location resulting from treatment with the first particle type, wherein the filter property isa porosity value, a permeability value, or combinations thereof; (Mental Process, Abstract Idea: The determining a value of a filter property, such as based on a rubric was performed before automation of fluid treatment. Therefore, it is practically performable in the mind or with the aid of pen and paper. Therefore, it is a mental process, an abstract idea.)
determining whether the first value of the filter property exceeds a threshold; (Mental Process, Mathematical Concept, Abstract Ideas – Comparing numbers or qualitative metrics is practically performable in the mind or with the aid of pen and paper. Also, comparing numbers is rudimentary math, a mathematical concept. These are abstract ideas.)
selecting a second particle type from the inventory of particle types, in response to determining that the first value of the filter property does not exceed the threshold; (Mental Process, Mathematical Concept, Abstract Ideas – Making a selection of an element based on the simple number comparison from a rubric is practically performable in the mind or with the aid of pen and paper. These are abstract ideas)
determining, by the particle model, a second value of the filter property at the fracture location resulting from treatment with the second particle type; (Mental Process, Abstract Idea – Determining a value from a rubric is practically performable in the mind or with the aid of pen and paper. These are abstract ideas)
determining whether the second value of the filter property exceeds the threshold; and (Mental Process, Mathematical Concept, Abstract Ideas – Comparing numbers or qualitative metrics is practically performable in the mind or with the aid of pen and paper. Also, comparing numbers is rudimentary math, a mathematical concept. These are abstract ideas.)
generating, by the design process, the fluid loss control treatment based on the second particle type and a concentration of the second particle type to form at the interface, in response to determining that the second value of the filter property exceeds the threshold, (Mental evaluation: [0004] “In fluid loss control treatments, the composition can include a LCM particle and a carrier fluid to suspend and transport the LCM particle to the target location, e.g., lost circulation zone. The type of LCM material can be selected based on the formation type, specific to an oil field, or specified by a customer. The fluid properties, such as density, of the carrier fluid may be tailored to the specific gravity of the LCM particle. The compatibility of the carrier fluid to the formation properties may limit the fluid properties of the carrier fluid. The effectiveness of the fluid loss control treatment can depend on selecting an effective LCM treatment based on the type of low pressure zone. A method of designing a well treatment with a LCM particle and carrier fluid compatible with the type of low pressure zone is desirable.” [0069] “A fluid loss event may be anticipated from a historical database of existing wellsites. At least one fluid loss control treatments can be designed based the drilling dataset from one or more offset wells within the same field. A request may be received from a customer device 136 for a fluid loss control treatment for a new wellsite within the same field as at least one offset wellsite. Turning now to FIG. 8, a method 800 of designing a fluid loss control treatment from offset well data is illustrated as a logic block diagram. The design process 124 of FIG. 3 may utilize at least one model 126 to generate a fluid loss control treatment for a known low pressure zone, e.g., fracture 336 of FIG. 3. At step 810, the design process 124 may retrieve a drilling dataset of an offset well from a historical database 128 located on storage computer 114. As previously described, the drilling dataset may include the daily drilling log, the mud log, the mud logging report, a sensor dataset from the fluid system, the lifting mechanism, the rotation mechanism, the wellhead, the BHA 10, or combinations thereof. The design process 124 may retrieve the drilling dataset from the historical database 128, the storage computer 114, the communication device 118, the remote wellsite 116, the customer device 136, the computer system 122, a virtual computer within the 5G network, or combinations thereof.” – People of ordinary skill in the art have been generating fluid loss control treatments with these methods since before automation.)
The steps are evaluations, which are mental processes a petroleum engineer could conduct using pen, paper, and/or a calculator. (See Examples 43 and 45 of the October 2019 Examples 43-46). The steps are also mathematical calculations, as illustrated in the specification.
Mental processes and mathematical concepts are abstract ideas.
Claim 19 recites an abstract idea.
Step 2A – Prong 2: Integrated into a Practical Application?
No.
See the MPEP sections cited in the eligibility analysis of claim 1.
The additional limitations:
retrieving, by a design process, a drilling dataset for at least one offset well proximate to a new wellsite, […];
The retrieving step merely gathers existing information (a dataset of a servicing operation at a wellbore) for evaluation. Mere data gathering is insignificant extra solution activity under MPEP 2106.05(g). Under Mere Data Gathering, an analogous example is provided: “iv. Obtaining information about transactions using the Internet to verify credit card transactions, CyberSource v. Retail Decisions, Inc., 654 F.3d 1366, 1375, 99 USPQ2d 1690, 1694 (Fed. Cir. 2011).” Under MPEP 2106.05(g), receiving data for evaluation is not significant in meaningfully limiting the invention, and the receiving of the data is necessary to the evaluations and mathematical operations of the claim. Under MPEP 2106.05(g). The retrieving step adds nothing more than insignificant extra solution activity, so it does not integrate the abstract idea into a practical application in Step 2A Prong Two.
Should it be found that the generating step is an additional limitation, rather than an element of the abstract idea, the generating step is token post-solution activity under MPEP 2106.05(g) and/or mere instructions to “apply it” under MPEP 2106.05(f). Also, the generating step merely limits the claim to a particular field of preparing a fluid loss control treatment under 2106.05(h). Therefore, the generating step fails to integrate the abstract idea into a practical application at Step 2A, Prong 2.
[…] computer-implemented […]
[…] executing on a computer system […]
[…] and wherein the computer system comprises a non-transitory memory and a processor […]
[…] particle model […]
The computer implementation is a recitation of a general purpose computer with no specific configurations to execute the claimed method. As such, the computer implementation implements the recited abstract idea on a generic computer, and, under MPEP 2106.05(f) does not integrate the abstract idea into a practical application in Step 2A Prong Two.
wherein particle-laden fluid is pumped into a wellbore according to the generated fluid loss control treatment.
This is an example of insignificant extra-solution activity analogous to the examples in MPEP 2106.05(g): i. Cutting hair after first determining the hair style, In re Brown, 645 Fed. App'x 1014, 1016-1017 (Fed. Cir. 2016) (non-precedential). Once you have designed a fluid control treatment, what other application is there for it than generally using it as a fluid control treatment in a wellbore. Because the wherein clause is insignificant extra-solution activity, under MPEP 2106.05(g), the wherein clause fails to integrate the abstract idea into a practical application.
Therefore, there are no additional limitations in claim 12 that integrate the abstract idea into a practical application under Step 2A, Prong 2.
Claim 19 does not integrate the abstract idea into a practical application and is directed to the abstract idea.
Step 2B: Claim provides an Inventive Concept?
No.
See the MPEP sections cited in the eligibility analysis of claim 1.
The additional limitations:
retrieving, by a design process, a drilling dataset for at least one offset well proximate to a new wellsite, […];
This retrieving step is storing and retrieving information from memory and also indicative of sending or reciting data, so it is analogous to the examples cited in MPEP 2106.05(d)(II)(i) representing well-understood, routine, and conventional functions. This receiving step is also akin to the limitation in Electric Power Group (See 2106.04(a)(2)(III)(D) “• A wide-area real-time performance monitoring system for monitoring and assessing dynamic stability of an electric power grid – Electric Power Group, 830 F.3d at 1351 and n.1, 119 USPQ2d at 1740 and n.1;” representing well-understood, routine, and conventional functions.
Because the additional limitation of the retrieving step is insignificant extra-solution activity (as illustrated under Step 2A Prong 2) and a well-understood, routine, and conventional function, the retrieving step fails to provide the abstract idea with significantly more to render the combination of the additional limitations with the other claim elements an inventive concept, under MPEP 2106.05(f) and MPEP 2106.05(g) respectively.
Should it be found that the generating step is an additional limitation, rather than an element of the abstract idea, the generating step is token post-solution activity under MPEP 2106.05(g) and/or mere instructions to “apply it” under MPEP 2106.05(f). Further, the generating step is well-recognized, routine, and conventional activity akin to the example in MPEP 2106.05(d)(II) “Below are examples of other types of activity that the courts have found to be well-understood, routine, conventional activity when they are claimed in a merely generic manner (e.g., at a high level of generality) or as insignificant extra-solution activity: […] v. Determining an estimated outcome and setting a price, OIP Techs., 788 F.3d at 1362-63, 115 USPQ2d at 1092-93.“ Also, the generating step merely limits the claim to a particular field of preparing a fluid loss control treatment under 2106.05(h). Therefore, the generating step fails to combine with the other elements to provide significantly more than the abstract idea that would confer an inventive concept at step 2B.
[…] computer-implemented […]
[…] executing on a computer system […]
[…] and wherein the computer system comprises a non-transitory memory and a processor […]
[…] particle model […]
The computer implementation is a recitation of a general purpose computer with no specific configurations to execute the claimed method. As such, the computer implementation implements the recited abstract idea on a generic computer, and, under MPEP 2106.05(f) fails to combine with the other elements of the claim to provide significantly more, and, therefore, fails to confer an inventive concept.
wherein particle-laden fluid is pumped into a wellbore according to the generated fluid loss control treatment.
This is an example of well-understood, routine, conventional (WURC) activity. Here is evidence: API Standard 65, Part 2, Second Edition, Dec. 2010, "Isolating Potential Flow Zones During Well Construction",§ 5.7.4 ,i 1, § 7.3 ,i 2, Appendix B, § B.2.4, the bulleted list for the cementing plan including "pump rates"; also§ 5.6.4 ,i 2: "Computer based thermal modeling programs may be used to develop cementing testing temperatures. Such programs require input information such as static temperature, formation and well fluid thermal characteristics, rheologies, estimated job volumes, planned pump rates and well geometry. The predictions generated by thermal modeling programs may vary significantly; operators may consider employing more than one thermal model to arrive at a cement test temperature schedule", and§ 5.6.5.5: "Some computer programs may be used to determine the type and volume of spacers to be pumped for drilling fluid removal and predict the degree of fluid (cement, spacer, drilling fluid) intermixing that may occur during placement.",§ 5.9.5 ,i,i 1-2 incl.: "Pumping the cement job with the designed pump rates is important but density control should not be sacrificed to obtain a planned rate." Because the wherein clause is WURC under MPEP 2106.05(d) and insignificant extra-solution activity under MPEP 2106.05(g), the wherein clause fails to combine with the other elements of the claims to provide significantly more than the abstract idea that would confer an inventive concept.
Therefore, there are no additional limitations in claim 19 that, in combination with other elements of the claim, furnish claim 19 with an inventive concept to ensure that claim 19, as a whole, amounts to significantly more than the bolded abstract idea under Step 2B.
Claim 19 is ineligible.
Dependent Claims
The dependent claims 2-11, 13-18, and 20 are also ineligible for at least the following reasons.
Claims 2 and 14
Claims 2 and 14 recite,
further comprising: determining, by a wellbore hydraulics model, the fluid loss rate by inputting the at least one dataset into the wellbore hydraulics model. (Evaluation of mathematical calculations using mathematical relationships: [0047] “The design process 124 can input the datasets as input values 412 into one or more models 126, for example, the wellbore hydraulics model 414. The wellbore hydraulics model 414 can determine output values” [0048] “The formation fracture model 424 can calculate the loss rate based on mathematical models of each type of fracture and generate a probability of the fluid loss rate being a resultant of each type of fracture.” [0051] “Below is another example equation that may be used to determine the loss rate”)
The determining step is an evaluation, which is a mental process, and represents mathematical operations on mathematical relationships (e.g., the recited models), which are mathematical concepts. Mental processes and mathematical concepts are abstract ideas.
The features of claims 2 and 14 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claims 2 and 14 are ineligible.
Claims 3 and 15
Claims 3 and 15 recite,
further comprising determining, by a formation fracture model, the fracture geometry, by inputting the fluid loss rate, the at least one dataset, or combinations thereof into the formation fracture model. (Evaluation of mathematical calculations using mathematical relationships: [0072]-[0073] “At step 818, the design process 124 may input the fluid loss rate and fluid loss mechanism into a fracture model 818. The fracture model 818 may be the formation fracture model 424 of method 400. The fracture model 818 can determine a probability of the fracture, e.g., fracture 336 of formation 316, being one of three types of fractures: a natural fracture, an induced fracture, or a highly permeable zone. The formation fracture model 818 can calculate the loss rate based on mathematical models of each type of fracture and generate a probability of the fluid loss rate being a resultant of each type of fracture. At step 822, the design process 124 can determine the fracture geometry with the greatest probability by comparing the results of the mathematical models. In some embodiments, the design process 124 may compare the results of the fracture model with first fluid density and rheology to the results of the fracture model with a second fluid density and rheology.”)
The determining step is an evaluation, which is a mental process, and represents mathematical operations on mathematical relationships (e.g., the recited models), which are mathematical concepts. Mental processes and mathematical concepts are abstract ideas.
The features of claims 3 and 15 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claims 3 and 15 are ineligible.
Claims 4 and 16
Claim 4 recites,
wherein the formation fracture model calculates a fracture as a natural fracture, or an induced fracture.
This merely adds another calculation, which is a mental evaluation of a mathematical calculation in textual form. Accordingly, this limitation is an element of the abstract idea, not an additional limitation. Claim 16 recites similar features and is treated the same under the eligibility analysis.
The features of claims 4 and 16 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claims 4 and 16 are ineligible.
Claim 5
Claim 5 recites,
designing, by the design process, a pumping procedure for the fluid loss control treatment, wherein the pumping procedure includes a volume and a flow rate of a carrier fluid. (Mental evaluation: [0093] “For example, circulation fluid model 938 may determine the carrier fluid density, rheology, and/or material properties to convey the design particle (step 934) at the desired concentration to the fracture, e.g., fracture 336, within the low pressure zone. The circulation model 938 may generate one or more volumes of fluid for transportation of the particles. For example, a first volume of fluid may be a spacer fluid and a second volume of fluid may be a carrier fluid. The circulation model 938 may determine the pumping rates for each volume of fluid. The output of the circulation model 938 may include a pumping procedure for at least one pumping unit.”)
The designing step is an evaluation, which is a mental process. Mental processes are abstract ideas.
Also, should it be found that the designing step is not an abstract idea, it is merely an example of “apply it” after the solution has already been determined under MPEP 2106.05(f). It is also token, post-solution, extra-solution activity akin to the example “i. Cutting hair after first determining the hair style, In re Brown, 645 Fed. App'x 1014, 1016-1017 (Fed. Cir. 2016) (non-precedential).” Accordingly, this is not an additional limitation that integrates the abstract idea into a practical application at Step 2A.
It is also is well-understood, routine, and conventional activity akin to the example MPEP 2106.05(d)(II) “v. Determining an estimated outcome and setting a price, OIP Techs., 788 F.3d at 1362-63, 115 USPQ2d at 1092-93;” Based on the deficiencies under 2106.05(f), 2106.05(g), and 2106.05(d), this is not an additional limitation that combines with the other elements of the claim to provide significantly more than the abstract idea that would confer an inventive concept a Step 2B.
The features of claim 5 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claim 5 is ineligible.
Claim 6
Claim 6 recites,
wherein the at least one dataset is selected from the group consisting of a fluid system dataset, a mud system dataset, a daily drilling report, a mud log, or combination thereof.
This merely describes the data gather in the receiving step and, is, therefore, an element of the mere information gathering and well-understood, routine, and conventional activity of the retrieving step. Further, this does not specify how the data is gathered.
The retrieving step merely gathers existing information (a dataset of a servicing operation at a wellbore) for evaluation. Mere data gathering is insignificant extra solution activity under MPEP 2106.05(g). Under Mere Data Gathering, an analogous example is provided: “iv. Obtaining information about transactions using the Internet to verify credit card transactions, CyberSource v. Retail Decisions, Inc., 654 F.3d 1366, 1375, 99 USPQ2d 1690, 1694 (Fed. Cir. 2011).” Under MPEP 2106.05(g), receiving data for evaluation is not significant in meaningfully limiting the invention, and the receiving of the data is necessary to the evaluations and mathematical operations of the claim. Under MPEP 2106.05(g). This further reinforced by the example from Electric Power Group in MPEP 2106.05(g): “iii. Selecting information, based on types of information and availability of information in a power-grid environment, for collection, analysis and display.” Also, the recited “group consisting of a fluid system dataset, a mud system dataset, a daily drilling report, a mud log, or combination thereof” merely limit the elements of the claim to a particular field under MPEP 2106.05(h). This is akin to the Electric Power Group example in MPEP 2106.05(h) “vi. Limiting the abstract idea of collecting information, analyzing it, and displaying certain results of the collection and analysis to data related to the electric power grid, because limiting application of the abstract idea to power-grid monitoring is simply an attempt to limit the use of the abstract idea to a particular technological environment,” The retrieving step adds nothing more than insignificant extra solution activity, so it does not integrate the abstract idea into a practical application in Step 2A Prong Two.
The retrieving step is storing and retrieving information from memory and also indicative of sending or reciting data, so it is analogous to the examples cited in MPEP 2106.05(d)(II)(i) representing well-understood, routine, and conventional functions under Step 2B. Because the additional limitation contributes nothing to the inventiveness of the claim under MPEP 2106.05(d), 2106.05(f), 2106.05(g), and 2106.05(h), the additional limitation fails to combine with the other elements of the claim to provide significantly more than the abstract idea that would confer an inventive concept at Step 2B.
The features of claim 6 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claim 6 is ineligible.
Claim 8
Claim 8 recites,
wherein the particle model utilizes an equation for determining the porosity value of the interface:
PNG
media_image1.png
95
327
media_image1.png
Greyscale
wherein D represents an average particle diameter; ϵ represents an estimated porosity based on empirical results; and φ represents a sphericity of the particle type forming the interface. (Evaluation of mathematical operations: [0064])
This is an evaluation of an equation, which is an evaluation, a mental process, and is a mathematical operation on a mathematical relationship (e.g., a model), which is a mathematical concept. Mental processes and mathematical concepts are abstract ideas. The features of claim 8 are abstract elements that merge with the abstract idea and do not provide any additional limitations.
The features of claim 8 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claim 8 is ineligible.
Claim 9
MPEP 2106.05(d): “On the other hand, Mayo Collaborative Servs. v. Prometheus Labs., Inc., 566 U.S. 66, 67, 101 USPQ2d 1961, 1964 (2010) provides an example of additional elements that were not an inventive concept because they were merely well-understood, routine, conventional activity previously known to the industry, which were not by themselves sufficient to transform a judicial exception into a patent eligible invention. Mayo Collaborative Servs. v. Prometheus Labs., Inc., 566 U.S. 66, 79-80, 101 USPQ2d 1969 (2012) (citing Parker v. Flook, 437 U.S. 584, 590, 198 USPQ 193, 199 (1978) (the additional elements were "well known" and, thus, did not amount to a patentable application of the mathematical formula)). In Mayo, the claims at issue recited naturally occurring correlations (the relationships between the concentration in the blood of certain thiopurine metabolites and the likelihood that a drug dosage will be ineffective or induce harmful side effects) along with additional elements including telling a doctor to measure thiopurine metabolite levels in the blood using any known process. 566 U.S. at 77-79, 101 USPQ2d at 1967-68. The Court found this additional step of measuring metabolite levels to be well-understood, routine, conventional activity already engaged in by the scientific community because scientists "routinely measured metabolites as part of their investigations into the relationships between metabolite levels and efficacy and toxicity of thiopurine compounds." 566 U.S. at 79, 101 USPQ2d at 1968.”
generating a sample of the fluid loss control treatment for at least one fracture; testing, by a laboratory test, a plurality of filtration properties of the fluid loss control treatment; and validating, by the laboratory test, the fluid loss control treatment in response to the filtration properties exceeding a threshold value.
The generating, testing, and validating steps represent a testing procedure after the inventive concept has already been performed. The test is on a the fluid loss treatment fluid to see if it works. This is insignificant extra-solution activity akin to the post solution activity of MPEP 2106.05(g) “ii. Testing a system for a response, the response being used to determine system malfunction, In re Meyers, 688 F.2d 789, 794; 215 USPQ 193, 196-97 (CCPA 1982);” – also cited to in 2106.04(a)(2)(II): “iii. a mental process that a neurologist should follow when testing a patient for nervous system malfunctions, In re Meyer, 688 F.2d 789, 791-93, 215 USPQ 193, 194-96 (CCPA 1982).” Testing the efficacy of the solution before introducing it into a wellbore at the expense of millions of dollars is a natural element that flows from a result of predicting a solution to introduce. Also, testing a fluid loss treatment that has been determined by a model is merely limiting the abstract idea to a particular environment. Because the limitations of claim 9 are insignificant extra-solution activity and merely limit the abstract idea to a field of use, the limitations of claim 9 fail to integrate the abstract idea into a practical application under Step 2A, Prong 2.
Further, under MPEP 2106.05(d) Testing fluid loss control treatments is a conventional activity because they are routinely performed by engineers creating a fluid loss control treatment to test the treatment before the expensive process of introducing the treatment to the wellbore according to API standards. (See e.g., The API STANDARD 65 Document (of record) “Isolating Potential Flow Zones During Well Construction, API STANDARD 65 – PART 2, SECOND EDITION, DECEMBER 2010”: Page 17, 4.6.3, Third Paragraph “[…] Laboratory tests, conducted under simulated downhole temperature and pressure conditions (within the limits of the laboratory equipment) with representative cement, additives and mix water shall indicate the sustained development of 50 psi compressive or sonic strength. Care should be taken that sonic strength continues to develop following the cement slurry's initial set and that the first "lime to 50 psi" reading is not an artifact of the initial temperature and pressure ramp used in the testing. See the example below (Figure 1) in which an initial "lime to 50 psi" is recorded in 29 minutes 30 seconds while the sustained development of 50 psi occurs in approximately 3 hrs 30 minutes.” Page 18 “A well-designed cement job optimizes cement placement through considerations such as laboratory-tested slurry design, honoring pore pressure/fracture gradient window, use of spacers/pre-flushes, proper density and rheological hierarchy, fluid compatibility and adequate centralization. This section summarizes many of the key drilling issues that affect the quality of a primary cementing operation. This section is not exhaustive, nor does it provide the reader with a comprehensive set of detailed recommendations for well construction. The intent is to highlight the salient aspects that should be considered and summarize the interrelationship between drilling operations and cementing success. All topics discussed are covered in detail in various API, ISO, and other industry publications.” – Laboratory tests of fluid loss control treatments are standard. Also, see Chevron (e.g., pages 12 and 166) cited in the 103 rejections.)
Because the limitations of claim 9 are insignificant extra-solution activity under MPEP 2106.05(g) and are well-understood, routine, and conventional functions, the limitations of claim 9 do not combine with the other elements of the claim from which claim 9 depends to provide significantly more or confer an inventive concept under Step 2B.
The features of claim 9 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claim 9 is ineligible.
Claims 10 and 17
Claims 10 and 17 recite,
mixing the fluid loss control treatment, by the pumping equipment, per the pumping procedure; and pumping the fluid loss control treatment per the pumping procedure.
The transporting, mixing, and pumping steps represent a procedure for introducing the fluid loss control treatment to a wellbore after the inventive concept has already been performed. This is token post-solution insignificant extra-solution activity akin to the post solution activity of MPEP 2106.05(g) “Insignificant Application: i. Cutting hair after first determining the hair style, In re Brown, 645 Fed. App'x 1014, 1016-1017 (Fed. Cir. 2016) (non-precedential).” “ii. Testing a system for a response, the response being used to determine system malfunction, In re Meyers, 688 F.2d 789, 794; 215 USPQ 193, 196-97 (CCPA 1982);” – also cited to in 2106.04(a)(2)(II): “iii. a mental process that a neurologist should follow when testing a patient for nervous system malfunctions, In re Meyer, 688 F.2d 789, 791-93, 215 USPQ 193, 194-96 (CCPA 1982).”Introducing a fluid loss control treatment to a wellbore after the treatment is determined is a natural element that flows from the abstract idea. Also, These steps are merely “apply it” steps under MPEP 2106.05(f) that merely apply the solution after it is determined. Because the limitations of claims 10 and 17 are insignificant extra-solution activity and merely limit the abstract idea to a field of use, the limitations of claims 10 and 17 fail to integrate the abstract idea into a practical application under Step 2A, Prong 2.
Further, under MPEP 2106.05(d) the limitations of claims 10 and 17 are considered well-understood, routine, and conventional under the aforementioned API Standards:
API Standard 65, Part 2, Second Edition, Dec. 2010, "Isolating Potential Flow Zones During Well Construction",§ 5.7.4 ,i 1, § 7.3 ,i 2, Appendix B, § B.2.4, the bulleted list for the cementing plan including "pump rates"; also§ 5.6.4 ,i 2: "Computer based thermal modeling programs may be used to develop cementing testing temperatures. Such programs require input information such as static temperature, formation and well fluid thermal characteristics, rheologies, estimated job volumes, planned pump rates and well geometry. The predictions generated by thermal modeling programs may vary significantly; operators may consider employing more than one thermal model to arrive at a cement test temperature schedule", and§ 5.6.5.5: "Some computer programs may be used to determine the type and volume of spacers to be pumped for drilling fluid removal and predict the degree of fluid (cement, spacer, drilling fluid) intermixing that may occur during placement.",§ 5.9.5 ,i,i 1-2 incl.: "Pumping the cement job with the designed pump rates is important but density control should not be sacrificed to obtain a planned rate"
With respect to transporting the blend, see§ 5.9 which details this, e.g.§ 5.9.2: "The service company providing the cement and/or cement blend should follow all established, documented company procedures to ensure that all received neat cement is within acceptable specifications upon arrival at the bulk plant", e.g.§ 5.9.2: "All cement blends should be stored and transported in properly maintained bulk storage tanks", e.g. page 80, table at the top of the page, the row for "Special Blending Mixing"
Because the limitations of claims 10 and 17 are insignificant extra-solution activity under MPEP 2106.05(g) and are well-understood, routine, and conventional functions, the limitations of claims 10 and 17 do not combine with the other elements of the claims from which claims 10 and 17 depend to provide significantly more or confer an inventive concept under Step 2B.
The features of claims 10 and 17 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claims 10 and 17 are ineligible.
Claims 11 and 18
Claim 11 recites,
wherein the inventory of particle types comprises particle types available at a wellsite.
This merely further limits by antecedent basis the fluid loss control treatment design that was transported in claim 10. This merely limits the claim elements to a particular field under MPEP 2106.05(h). This is akin to the example in MPEP 2106.05(h) from Electric Power Group: “vi. Limiting the abstract idea of collecting information, analyzing it, and displaying certain results of the collection and analysis to data related to the electric power grid, because limiting application of the abstract idea to power-grid monitoring is simply an attempt to limit the use of the abstract idea to a particular technological environment.” Because of this, this additional limitation neither integrates the abstract idea into a practical application at step 2A, Prong 2 nor combines with the other elements of the claim to provide significantly more than the abstract idea that would confer an inventive concept at Step 2B.
The features of claims 11 and 18 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claims 11 and 18 are ineligible.
Claim 13
Claim 13 recites,
further comprising: processing the at least one real-time dataset to generate a periodic dataset.
The processing step is an evaluation, which is a mental process, an abstract idea. (Mental evaluation: [0086] “The equipment datasets may be periodic dataset from equipment sensors such as pressure transducers, flowrate sensors, positional sensors, valve position sensors, or combinations thereof. The design process 124 may process the data from the equipment datasets. The data processing may include transformation of sensor data measurements into data values. The data processing may include the generation of a wellbore path and trajectory based on distance measured along the axis of the wellbore 6. The equipment dataset can include fluid system datasets comprising periodic datasets of circulation pressure, density, rheology, fluid loss, chemical properties, and solids control.”)
The features of claim 13 do not provide additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claim 13 is ineligible.
Claim 20
Claim 20 recites,
further comprising: transporting a well servicing operation comprising a pumping equipment to a new wellsite, wherein the pumping equipment includes a unit controller, and wherein the unit controller comprises a processor and memory;
transporting the fluid loss control treatment comprising an inventory of fluid loss control material to the new wellsite, and wherein the inventory includes at least two supplies of fluid loss control materials; (API Standards
receiving, by the unit controller, a design for the fluid loss control treatment, wherein the design comprises at least one of the supplies of fluid loss control materials and a pumping procedure;
connecting the pumping equipment to the wellbore, wherein the pumping equipment is fluidically connected to the wellbore;
mixing a fluid loss control treatment, by the unit controller, per the pumping procedure; and
pumping the fluid loss control treatment per the pumping procedure.
The transporting steps, receiving step, connecting step, and mixing steps represent a procedure for producing the fluid loss control treatment at a wellbore site after the inventive concept has already been performed. These represent “apply it” steps after the solution has already been performed, under MPEP 2106.05(f). This includes the generic controller.
The transporting steps, receiving step, connecting step, and mixing steps represent a procedure for producing the fluid loss control treatment at a wellbore site after the inventive concept has already been performed. This is insignificant extra-solution activity akin to the post solution activity of MPEP 2106.05(g) “Insignificant Application: i. Cutting hair after first determining the hair style, In re Brown, 645 Fed. App 1014, 1016-1017 (Fed. Cir. 2016).” Producing a fluid loss control treatment at a wellbore after the treatment is determined is a natural element that flows from the abstract idea. Moving and connecting the equipment for doing so are just necessary steps for using the abstract idea in the ordinary course of activity. But for the generic computer, the receiving and mixing steps are those that would be done by an engineer on site to implement the solution. Using the generic controller to do so is merely applying it to a computer, as previously demonstrated. Because the transporting steps, receiving step, connecting step, and pumping step merely apply the abstract idea (“apply it”) after the fact under MPEP 2106.05(f) and are token, post-solution, insignificant, extra-solution activity under MPEP 2106.05(f), they do not integrate the abstract idea into a practical application at Step 2A, Prong 2.
As Demonstrated In a 1993 Textbook called “Cementing Technology and Procedures” by Association de recherche sur les techniques d'exploitation de petrol. The following image from Chapter 2, Page 32 shows:
PNG
media_image2.png
807
597
media_image2.png
Greyscale
This illustrates a wellsite, where equipment did not appear naturally as trees in a forest. Everything is transported to the wellsite because the equipment was not there naturally. If Applicant disagrees, Applicant is invited to demonstrate situations in which these elements naturally spring forth from the earth. Even still, the elements are transported from the earth. The slurry’s constituent elements (e.g., water and cement) are transported at the very least, from the cement silo to the slurry preparation tank and the pumping unit. (This illustrates the well-understood, routine, and conventional nature of the transporting steps) As is illustrated in the image from the textbook, The pumping unit is attached to the wellbore. It did not connect itself. (This illustrates the well-understood, routine, and conventional nature of the connecting step) There is a slurry preparation tank that mixes the slurry blend for the fluid loss control treatment. (This illustrates the well-understood, routine, and conventional nature of the mixing step) The mix is made to specification of a fluid loss control treatment plan, as is demonstrated in Chapter 1 of the same textbook, pages 4-16. (This illustrates the well-understood, routine, and conventional nature of the receiving step as it pertains specifically to the fluid loss control treatment) Further, receiving data is well-understood, routine, and conventional activity according to the examples in MPEP 2106.05(d) “i. Receiving or transmitting data over a network, e.g., using the Internet to gather data […] iii. Electronic recordkeeping […] iv. Storing and retrieving information in memory). As for pumping, the pumping unit connected to the wellbore for the purpose of pumping slurry is there to pump. For example, see the same textbook on Page 33, with an image demonstrating the aforementioned pumping. Also, the Applicant is directed to the Chevron reference (e.g., pages 12 and 166) in the 35 USC 103 rejections.
PNG
media_image3.png
501
560
media_image3.png
Greyscale
Therefore, but for generic computer implementation of some steps by a generic controller, the transporting steps, receiving step, connecting step, and pumping step are well-understood, routine, and conventional activities, under MPEP 2106.05(d) and have been textbook standard activities for fluid loss control since, at least, 1993. Because the transporting steps, receiving step, connecting step, and pumping step are well-understood, routine, and conventional activities under MPEP 2106.05(d), merely apply the abstract idea (“apply it”) under MPEP 2106.05(f), and are insignificant extra-solution activity under MPEP 2106.05(g), they fail to combine with the other elements of the claim to provide significantly more than the abstract idea, which would confer an inventive concept at Step 2B.
The features of claim 20 do not provide further additional limitations to integrate the abstract idea into a practical application under Step 2A, Prong 2 or combine with the other elements of the claim to contribute significantly more than the abstract idea to render the combination an inventive concept under Step 2B.
Claim 20 is ineligible.
Claim 21 Claim 21 recites,
Wherein the generating of the fluid loss control treatment further comprises iterating a fluid property, wherein the fluid property comprises fluid density or fluid rheology. (This merely characterizes the data used in the determination which merely limits the abstract idea to a particular technological environment and fails to confer eligibility under MPEP 2106.05(h).)
Claim 21 is ineligible.
Claim Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
The factual inquiries for establishing a background for determining obviousness under pre-AIA 35 U.S.C. 103(a) are summarized as follows:
1. Determining the scope and contents of the prior art.
2. Ascertaining the differences between the prior art and the claims at issue.
3. Resolving the level of ordinary skill in the pertinent art.
4. Considering objective evidence present in the application indicating obviousness or nonobviousness.
This application currently names joint inventors. In considering patentability of the claims under pre-AIA 35 U.S.C. 103(a), the examiner presumes that the subject matter of the various claims was commonly owned at the time any inventions covered therein were made absent any evidence to the contrary. Applicant is advised of the obligation under 37 CFR 1.56 to point out the inventor and invention dates of each claim that was not commonly owned at the time a later invention was made in order for the examiner to consider the applicability of pre-AIA 35 U.S.C. 103(c) and potential pre-AIA 35 U.S.C. 102(e), (f) or (g) prior art under pre-AIA 35 U.S.C. 103(a).
Claims 1-2, 5-6, 9, and 19: Loe, Chang, and Chevron.
Claims 1-2, 5-6, 9, and 19 rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over US 2009/0188718 A1 to Kaageson-Loe et al. (Loe) in view of NPL: “When Should We Worry About Supercharging in Formation-Pressure-While-Drilling Measurements?” by Chang et al. (Chang), and NPL: “Loss Circulation Guide” by Chevron. (Chevron).
Regarding Claim 1, Loe teaches,
A computer-implemented method of designing a wellbore fluid treatment, comprising: (Loe [0013] “In another aspect, embodiments disclosed herein relate to a method for treating drilling fluid loss at a drilling location, the method including calculating a drilling fluid loss rate at the drilling location, classifying the drilling fluid loss based on the drilling fluid loss rate or pressure in the loss zone, and selecting a solution based at least in part on the classifying.”.; [0114] “Embodiments of the invention may be implemented on virtually any type of computer regardless of the platform being used.” With respect to the computer implementation of steps, even if a person of ordinary skill in the art would interpret the steps as being conducted manually, e.g., by an engineer, rather than a computer, MPEP 2111 and MPEP 2144.04(III) show that a person of ordinary skill in the art would find it obvious to automate the steps of the references using a computer because a computer would do so faster. This is simply automating of what might be a manual activity using a computer, which is obvious in light of In re Prater.)
retrieving, by a design process executing on a processor, at least one dataset of a servicing operation at a wellbore; determining, by the design process, a fluid loss rate (Loe [0090] “Planning the wellbore may initially include defining drilling data for drilling at least a segment of a planned wellbore. The segment may include, for example, a predetermined length, a specific formation, a time period, and a wellbore depth. Drilling data may include any data that may be used to plan wellbores, such as wellbore lithology, porosity, tectonic activity, fracture gradient, fluid type, fluid properties, hydraulic pressure, fluid composition, well path, rate of penetration, weight on bit, torque, trip speed, bottom hole assembly design, bit type, drilling pipe size, drill collar size, and casing location. Drilling data may include offset well data, experience data collected from similar drilling operations, or data such as that collected during prior remedial treatment operations.” [0028] “Further, the severity of the fluid loss will be related to the cause of the lost circulation, and may be characterized by the pressure within the loss zone and by the rate of fluid loss. The pressure in the loss zone can be estimated based, in part, on the fluid volume added to top-off the well, i.e., the fluid volume required to re-fill the well. Specifically, the pressure within the loss zone may calculated as follows” [0055] ” If the fluid loss is not determined to be a surface loss (ST103), thereby resulting in a no condition, the drilling engineer should proceed with measuring the rate of fluid loss (ST105). The measured rate of fluid loss (ST105) may thus include calculating the fluid loss rate at the drilling location. As described in detail above, the rate of fluid loss (ST103) may be classified based on a rate of fluid loss in cubic meters lost per hour. As illustrated, in this embodiment, the fluid loss is classified as either a seepage loss (ST106), a partial loss (ST107), or a severe/total loss (ST108). As described above, seepage losses include losses less than three cubic meters per hour, while partial losses include loses from three to ten cubic meters per hour, and severe/total losses are losses of greater than 10 cubic meters per hour.”)
determining, by the design process, a fracture location within the wellbore; (Loe [0023] “Alternatively, lost circulation may be the result of drilling-induced fractures. For example, when the pore pressure (the pressure in the formation pore space provided by the formation fluids) exceeds the pressure in the open wellbore, the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is typically maintained at a higher pressure than the pore pressure. While it is highly advantageous to maintain the wellbore pressures above the pore pressure, on the other hand, if the pressure exerted by the wellbore fluids exceeds the fracture resistance of the formation, a formation fracture and thus induced mud losses may occur. Further, with a formation fracture, when the wellbore fluid in the annulus flows into the fracture, the loss of wellbore fluid may cause the hydrostatic pressure in the wellbore to decrease, which may in turn also allow formation fluids to enter the wellbore. As a result, the formation fracture pressure typically defines an upper limit for allowable wellbore pressure in an open wellbore while the pore pressure defines a lower limit. Therefore, a major constraint on well design and selection of drilling fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients though the depth of the well.” [0028] “Specifically, the pressure within the loss zone may calculated as follows: […] Dz is the true vertical depth (TVD) of the loss zone (m))” [0052] “In alternate embodiments, a drilling engineer may check for fluid loss (ST100) at selected depth intervals. In such an embodiment, a check for fluid loss (ST100) may occur, for example, in 25, 50, or 100 foot increments. In still other operations, a drilling engineer may check for fluid loss (ST100) when drilling switches between formation types or only when fluid volume loss is reported. Those of ordinary skill in the art will appreciate that offset well data may be used to predict areas that may result in fluid loss, and in such locations, more frequent fluid loss checks (ST100) may be performed.”)
generating a fluid loss control treatment by particle type iteration, comprising: selecting a first particle type from an inventory of particle types: (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid – The new is made with a first particle.)
determining, by a particle model, a first value of a filter property at the fracture location resulting from treatment with the first particle type, wherein the filter property is a porosity value, a permeability value, or combinations thereof; (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid, as well as determining a rate of LCM addition to the fluid. After the amount of LCM required to continue the preventative treatment is determined (ST408),” [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity based on treatment with a first particle.)
determining whether the first value of the filter property exceeds a threshold; (Loe [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity value is better than expected/no longer exceeds a threshold for the use of the particle, e.g., a large particle.)
selecting a second particle type from the inventory of the particle types, in response to determining that the first value of the filter property does not exceed the threshold; (Loe [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity value is better than expected/no longer exceeds a threshold for the use of the particle, e.g., a large particle. [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid – The new solution is made with a new particle based on determining that such a large particle is not needed for porosity below a threshold for that particle.)
determining, by the particle model, a second value of the filter property at the fracture location resulting from treatment with the second particle type; (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid, as well as determining a rate of LCM addition to the fluid. After the amount of LCM required to continue the preventative treatment is determined (ST408),” [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity based on treatment with a second particle.)
determining whether the second value of the filter property exceeds the threshold; (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid – The new solution with the new particle is determined to meet the porosity threshold (e.g., a correct particle type to deal with that porosity).)
generating, by the design process, the fluid loss control treatment based on the second particle type and a concentration of the second particle type to format the interface, in response to determining that the second value of the filter property exceeds the threshold, (Loe [0036] “For low fluid loss, particle-based treatments, a treatment blend solution may be based on a particle size distribution that follows the Ideal Packing Theory is designed to minimize fluid loss. Further discussion of selection of particle sizes required to initiate a bridge may be found in SPE 58793, which is herein incorporated by reference in its entirety. In order to achieve plugging or bridging, a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture” [0057] “As illustrated, for a seepage loss (ST106), a drilling engineer may be presented with several solutions for a loss control material to pump downhole, in this embodiment Blend #1 (ST106 a), Blend #2 (ST106 b), and Blend #3 (ST106 c). Each blend may be pre-selected as an appropriate blend for a rate of loss classified as a seepage loss (ST106). For example, in one embodiment, blends (ST106 a-c) may include a plurality of blends selected based on a determined fracture width and the type of fluid being used. In one embodiment, Blend #1 (ST106 a) may include a blend of loss control material selected to seal fractures up to 1000 μm, while Blend #2 (ST106 b) may include a blend of loss control material selected to seal fractures up to 1500 μm. In such an embodiment, Blend #3 (ST106 c) may be selected to include an alternate blend of loss control material capable of sealing fractures of up to 150 μm.” – Having determined the particle type satisfies the threshold (e.g., a particle type to plug a certain fracture), a new fluid treatment is created with the particle type.)
wherein particle laden fluid is pumped into a wellbore according to the generated fluid loss control treatment (Loe [0044] “The term “settable fluid” as used herein refers to any suitable liquid material which may be pumped or emplaced downhole, and will harden over time to form a solid or gelatinous structure and become more resistance to mechanical deformation.” [0045] “Formation, pumping, and setting of a cement slurry is known in art, and may include the incorporation of cement accelerators, retardants, dispersants, etc., as known in the art, so as to obtain a slurry and/or set cement with desirable characteristics. “Gunk” as known in the art refers to a LCM treatment including pumping bentonite (optionally with polymers or cementious materials” [00560 “For a seepage loss (ST106), the options for solving the fluid loss may include pumping one or more loss control blends (in this embodiment, one selected from three choices) downhole.”) which will harden upon exposure to water to form a gunky semi-solid mass, which will reduce lost circulation.” [0060] “After one of blends (ST106 a-c) is pumped downhole (i.e., the solution is implemented), the drilling engineer determines whether the blend was successful (ST109) in resolving the fluid loss. If the fluid loss is resolved, the drilling engineer may continue to drill ahead (ST101). However, if the blend did not resolve the fluid loss, the drilling engineer determines whether the measured rate of loss (ST105) is the same, has decreased, or has increased. If the measured rate of loss has remained the same, or is still classified as a seepage loss (ST106), the drilling engineer may repeat the selection of a blend, including either re-pumping the same blend, or selecting a new blend within the matrix.” – The treatments are pumped down the wellbore.)
While Loe does not appear to explicitly teach the following feature (Loe [0055] “The measured rate of fluid loss (ST105) may thus include calculating the fluid loss rate at the drilling location. As described in detail above, the rate of fluid loss (ST103) may be classified based on a rate of fluid loss in cubic meters lost per hour.” [0085] “HTHP test devices typically include a container including a disc, such as a perforated ceramic disc, whereby a sample of the drilling fluid procured from the return flow of drilling fluid is placed into the container under a specified temperature and pressure, and then the amount of fluid passing through the disc is measured. Based on the amount of fluid that passed through the disc, the fluid loss downhole may be estimated.”), Loe in view of Chang teaches:
determining, by the design process, a fluid loss rate from the at least one dataset; (Chang Page 173, Right Column, Last Paragraph “The associated fluid-loss rate is
q
t
=
S
∆
p
t
-
1
/
2
2
)” See also other developed fluid loss equations A-13, A-14, and A-18 on Page 174.” – Chang uses a measured pressure difference
∆
p
, which relies on a pressure in the borehole, an element of the at least one dataset.)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the determination of a fluid loss rate as an intermediate value for determining a fluid loss treatment of Loe by the specific equation for fluid loss determined based on measured pressure differences for determining fluid loss treatment properties in Chang because a person of ordinary skill in the art would be motivated, based on the expressed aim to determine particle sizes in a fluid loss mud based on formation pressures and fluid loss rates in Loe, to look to Chang for dynamic systems that are useful to aid in the planning, understanding, and interpretation (e.g., via fluid loss rates) of formation-pressure measurements while drilling. (Loe [0024] “A particularly challenging situation arises in depleted reservoirs, in which high pressured formations are neighbored by or inter-bedded with normally or abnormally pressured zones.” [0034] “The result of the type, quantification, and analysis of losses, formation/fracture type, and pressures within the loss zone may be then used to decide the type of curing method to be used.” [0039] “LCM treatments may include particulate- and/or settable-based treatments. The various material parameters that may be selected may include 1) material type in accordance with considerations based on drilling fluid compatibility, rate of fluid loss, fracture width, and success of prior treatments, etc., 2) the amount of treatment materials, in accordance with the measured or anticipate rate of fluid loss, and 3) particle size and particle size distribution, in accordance with pressure levels, formation type, fracture width, etc.” [0042] “However, the fracture width may be dependent, amongst other factors, upon the strength (stiffness) of the formation rock and the extent to which the pressure in the wellbore is increased to above initial fracture pressure of the formation during the fracture induction (in other words, the fracture width is dependent on the pressure difference between the drilling mud and the initial fracture pressure of the formation during the fracture induction step).”; Chang Page 1, Summary “A model is described that is capable of simulating in detail the time variation of formation pressures measured while drilling, in situations where supercharging is significant. Simulation results illustrate the variation of supercharging pressures with formation permeability, drilling-fluid-filtration properties, and drilling-fluid hydraulics. The model is used to explore how drilling operations influence the levels of supercharging when drilling two formations, widely separated along the well trajectory, and of significantly different permeabilities. The forward-simulation capability presented is believed to be a useful aid to the planning, understanding, and interpretation of formation-pressure measurements while drilling.” Also, see the relationships between formation pressures and fluid loss rates in equations A-13 and A-14 on page 174)
While Loe and Chang do not appear to explicitly teach the following feature Loe and Chang in view of Chevron teaches,
generating, by the design process, a fluid loss control treatment based on the second particle type and a concentration of the second particle type to form the interface, in response to determining that the second value of the filter property exceeds the threshold. (Chevron Pages 32-33 THE BENTONITE-DIESEL OIL (BDO) OR BENTONITE-SYNTHETIC OIL (BSO) SLURRY AND SQUEEZE IN WATER BASED DRILLING FLUIDS “Formula: 1. 300-400 pounds bentonite 2. 1 bbl of diesel oil, mineral oil or synthetic oil (final volume 1.42 bbl) 3. Lost circulation material optional at 10-12 ppb. 4. Barite as needed for density Squeeze Procedure: 1. Locate loss zone and run in hole open ended. Ideally, the loss zone should be known so the BDO can be placed efficiently where needed. If hole conditions allow place the pipe just above the loss zone, if not place the end of the pipe inside the casing. 2. Determine the volume of slurry to pump. Typically, a 40 barrel pill is used. It is advisable to mix in 10 bbl increments as to provide easier cleanup of the pumping equipment. 3. Pump a 5-10 bbl base oil spacer ahead and behind the slurry. 4. Pump pill to bottom of pipe and follow spacer with drilling fluid. 5. Close the blow out preventers. 6. Pump the slurry out the drill string at 1-2 bbl/minute and pump drilling fluid into annulus at 4-8 bbl/min for a thinner initial slurry pump at 8-16 bbl per minute down the annulus. 7. When one half the slurry from drill string is displaced; reduce pump rates to 1 bbl/min on the drill pipe and 1-3 bbl/min on the annulus. 8. When desired pressure is reached, maintain pressure on casing. Displace the drill string volume with drilling fluid and pull into casing. 9. Maintain pressure on the well for approximately 3 hours. 10.Circulate and condition the drilling fluid in the casing, and wash and ream the open hole slowly to bottom. This avoids pushing the bit into the BDO slurry and possibly pressuring up the hole causing lost circulation to reoccur. Note: As the BDO pill is circulated to the surface the shale shaker may blind and should be closely watched to prevent mud losses across the screens. BDO pills are not incorporated into the drilling fluid and are not saved for future use! Do not attempt to reverse out unused BDO, as the pipe is likely to become plugged!”- These fluid treatments generated are based on concentration and particle type to form the interface.)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the high-level descriptions of fluid loss control treatments in Loe by the specific pump procedures and LCM mixtures of Chevron because a person of ordinary skill in the art would be motivated based on the desire to optimize fluid loss control treatments expressed in Loe using the specific blends in Chevron that can bring a dysfunctional/leaking well back to operation with the benefit of 180 years of total experience in the methods. (Loe [0003] “Embodiments disclosed herein relate generally to lost circulation experienced during drilling a wellbore. In particular, embodiments disclosed herein relate to the detection, classification, and remedial treatment of lost circulation occurrences. Additionally, embodiments disclosed herein also relate to the anticipation of lost circulation during wellbore planning and preventative treatments to minimize the occurrences of such lost circulation.” [0029] “Additionally, the severity may also be classified by the rate at which the fluid is being lost. Specifically, loss rates may be classified into general categories of seepage loss (less than 3 m3/hr), partial loss (3-10 m3/hr) where some fluid is returned to the surface, and severe to total loss (greater than 10 m3/hr) where little or no fluid is returned to the surface through the annulus.”; Chevron Page 4, LOSS OF CIRCULATION FOREWARD “In a broad survey conducted by Drilling Specialties Company loss of circulation was identified as the most costly problem faced by the oil and gas industry associated with drilling fluids. The purpose of this CD is to inform the reader of the nature of this problem and ways to solve it. This CD was prepared by a team of individuals that combined have over 180 years’ experience in the drilling fluids business.”)
Regarding claim 2, Loe, Chang, and Chevron teach:
determining, by a wellbore hydraulics model, the fluid loss rate by inputting the at least one dataset into the wellbore hydraulics model. (Loe in view of Chang Page 173, Right Column, Last Paragraph “The associated fluid-loss rate is
q
t
=
S
∆
p
t
-
1
/
2
2
)” See also other developed fluid loss equations A-13, A-14, and A-18 on Page 174. This uses the dataset of Loe for pressure values.)
Regarding claim 5, Loe, Chang, and Chevron teach:
further comprising: designing, by the design process, a pumping procedure for the fluid loss control treatment, wherein the pumping procedure includes a volume and a flow rate of a carrier fluid. (Loe (the general treatment and procedure as previously mapped above) in view of Chevron Pages 32-33 THE BENTONITE-DIESEL OIL (BDO) OR BENTONITE-SYNTHETIC OIL (BSO) SLURRY AND SQUEEZE IN WATER BASED DRILLING FLUIDS “Formula: 1. 300-400 pounds bentonite 2. 1 bbl of diesel oil, mineral oil or synthetic oil (final volume 1.42 bbl) 3. Lost circulation material optional at 10-12 ppb. 4. Barite as needed for density Squeeze Procedure: 1. Locate loss zone and run in hole open ended. Ideally, the loss zone should be known so the BDO can be placed efficiently where needed. If hole conditions allow place the pipe just above the loss zone, if not place the end of the pipe inside the casing. 2. Determine the volume of slurry to pump. Typically, a 40 barrel pill is used. It is advisable to mix in 10 bbl increments as to provide easier cleanup of the pumping equipment. 3. Pump a 5-10 bbl base oil spacer ahead and behind the slurry. 4. Pump pill to bottom of pipe and follow spacer with drilling fluid. 5. Close the blow out preventers. 6. Pump the slurry out the drill string at 1-2 bbl/minute and pump drilling fluid into annulus at 4-8 bbl/min for a thinner initial slurry pump at 8-16 bbl per minute down the annulus. 7. When one half the slurry from drill string is displaced; reduce pump rates to 1 bbl/min on the drill pipe and 1-3 bbl/min on the annulus. 8. When desired pressure is reached, maintain pressure on casing. Displace the drill string volume with drilling fluid and pull into casing. 9. Maintain pressure on the well for approximately 3 hours. 10.Circulate and condition the drilling fluid in the casing, and wash and ream the open hole slowly to bottom. This avoids pushing the bit into the BDOslurry and possibly pressuring up the hole causing lost circulation to reoccur. Note: As the BDO pill is circulated to the surface the shale shaker may blind and should be closely watched to prevent mud losses across the screens. BDO pills are not incorporated into the drilling fluid and are not saved for future use! Do not attempt to reverse out unused BDO, as the pipe is likely to become plugged!)
Regarding claim 6, Loe, Chang, and Chevron teach:
wherein the at least one dataset is selected from the group consisting of a fluid system dataset, a mud system dataset, a daily drilling report, a mud log, or combination thereof. (Loe [0087] “Such properties may be determined by use of measurement while drilling and/or logging while drilling tools, as well as mud log data, that is typically available at the drilling rig site.”)
Regarding claim 9, Loe, Chang, and Chevron teach the features of claim 1. Chevron further teaches:
further comprising: generating a sample of the fluid loss control treatment for at least one fracture; (Chevron Page 25, Last Paragraph “A service company laboratory should test all slurries before they are pumped.”)
testing, by a laboratory test, a plurality of filtration properties of the fluid loss control treatment; and (Chevron Page 66 “The data showing the effect of DynaRed™ Fiber on return permeability was generated by an independent laboratory. The return permeability test procedure and test results are in this report. Samples A and B were prepared in the Drilling Specialties Company laboratory. Sample formulations were as follows: • Sample A: Two 100 ml tap water + 60.0g bentonite clay (mixed 5 minutes) + 0.5 ml of 50% W/V NaOH solution (mixed 15 minutes) + 4.5g Drispac Regular polymer (mixed 20 minutes) + 120g Rev dust to represent drill solids (mixed 2 hours). • Sample B: Sample A + 5.0 ppb DynaRed™ Fiber – fine grind ( mixed 20 minutes) Procedure: • Two 1” diameter plugs were drilled from a block of standard Berea sandstone. The plugs were cleaned in a Soxhlet extractor using methanol to remove hydrocarbons, pore water and salt. After drying, ambient permeability to air and the porosity by Boyle’s Law helium expansion was determined for each plug. • The core plugs were then saturated with a 35,000 ppm NaCl solution and each loaded into Hassler core holders and confined at an overburden pressure of 1,500psi. The permeability to brine was then determined for each plug. • Each drilling fluid sample was then flowed through a core plug in the opposite direction to the brine flow. A drilling fluid pressure 50 psi greater than the pore pressure was maintained for a period of 4 hours. Brine was then flowed in the original direction and the final brine permeability was determined after 20, 50, and 80 pore volumes of displacement through the core plug. Results: The results are presented in the following table and in the attached graphs. Graphical data is presented in two versions: 1. Brine permeability in millidarcies versus pore volumes produced and 2. Normalized permeability versus cumulative pore volumes produced”)
validating, by the laboratory test, the fluid loss control treatment in response to the filtration properties exceeding a threshold value. (Chevron Page 12, Third and Fourth Paragraphs “Note on LCM materials: Lost circulation materials come in many different forms, each may possess a specific advantage such as cost, availability, performance and effect or lack of effect on drilling fluid properties. There is no magical product as performance of an LCM is controlled primarily by its concentration and distribution of its particle size and shape. Particle size is mostly controlled by the sorting or milling process and particle shape by the source of material. It is commonly thought that the ratio of particle size of the mud to the fracture gap width controls the bridging process. When the ratio of the particle size to fracture gap width is less than 1/6, whole drilling fluid will pass through the formation and bridging will not occur. A ratio of ½ or greater will cause bridging and the formation of a filter cake to form immediately. Values in-between these two ratios will permit particle invasion and bridging until the bridges ratio is greater than ½ and the filter cake forms.)
Claim 19
Regarding claim 19, Loe teaches:
A computer-implemented method of designing a fluid loss control treatment, comprising: (Loe [0013] “In another aspect, embodiments disclosed herein relate to a method for treating drilling fluid loss at a drilling location, the method including calculating a drilling fluid loss rate at the drilling location, classifying the drilling fluid loss based on the drilling fluid loss rate or pressure in the loss zone, and selecting a solution based at least in part on the classifying.” – This is a method of designing a wellbore fluid treatment.; [0114] “Embodiments of the invention may be implemented on virtually any type of computer regardless of the platform being used.” – The method is computer-implemented. With respect to the computer implementation of steps, even if a person of ordinary skill in the art would interpret the steps as being conducted manually, e.g., by an engineer, rather than a computer in the references cited, MPEP 2111 and MPEP 2144.04(III) show that a person of ordinary skill in the art would find it obvious to automate the steps of the references using a computer because a computer would do so faster. This is simply automating of what might be a manual activity using a computer, which is obvious in light of In re Prater.)
retrieving, by a design process executing on a computer system, a drilling dataset for at least one offset well proximate to a new wellsite, and wherein the computer system comprises a non-transitory memory and a processor; determining, (Loe [0090] “Planning the wellbore may initially include defining drilling data for drilling at least a segment of a planned wellbore. The segment may include, for example, a predetermined length, a specific formation, a time period, and a wellbore depth. Drilling data may include any data that may be used to plan wellbores, such as wellbore lithology, porosity, tectonic activity, fracture gradient, fluid type, fluid properties, hydraulic pressure, fluid composition, well path, rate of penetration, weight on bit, torque, trip speed, bottom hole assembly design, bit type, drilling pipe size, drill collar size, and casing location. Drilling data may include offset well data, experience data collected from similar drilling operations, or data such as that collected during prior remedial treatment operations.” [0028] “Further, the severity of the fluid loss will be related to the cause of the lost circulation, and may be characterized by the pressure within the loss zone and by the rate of fluid loss. The pressure in the loss zone can be estimated based, in part, on the fluid volume added to top-off the well, i.e., the fluid volume required to re-fill the well. Specifically, the pressure within the loss zone may calculated as follows” [0055] ” If the fluid loss is not determined to be a surface loss (ST103), thereby resulting in a no condition, the drilling engineer should proceed with measuring the rate of fluid loss (ST105). The measured rate of fluid loss (ST105) may thus include calculating the fluid loss rate at the drilling location. As described in detail above, the rate of fluid loss (ST103) may be classified based on a rate of fluid loss in cubic meters lost per hour. As illustrated, in this embodiment, the fluid loss is classified as either a seepage loss (ST106), a partial loss (ST107), or a severe/total loss (ST108). As described above, seepage losses include losses less than three cubic meters per hour, while partial losses include loses from three to ten cubic meters per hour, and severe/total losses are losses of greater than 10 cubic meters per hour.” [0085] “HTHP test devices typically include a container including a disc, such as a perforated ceramic disc, whereby a sample of the drilling fluid procured from the return flow of drilling fluid is placed into the container under a specified temperature and pressure, and then the amount of fluid passing through the disc is measured. Based on the amount of fluid that passed through the disc, the fluid loss downhole may be estimated.” Claim 10 “A processor; and a machine-readable medium having instructions thereon that are executable by the processor to cause the processor to, log, during the injecting, measurements […]”)
determining, by the design process, a fracture location within the wellbore; (Loe [0023] “Alternatively, lost circulation may be the result of drilling-induced fractures. For example, when the pore pressure (the pressure in the formation pore space provided by the formation fluids) exceeds the pressure in the open wellbore, the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is typically maintained at a higher pressure than the pore pressure. While it is highly advantageous to maintain the wellbore pressures above the pore pressure, on the other hand, if the pressure exerted by the wellbore fluids exceeds the fracture resistance of the formation, a formation fracture and thus induced mud losses may occur. Further, with a formation fracture, when the wellbore fluid in the annulus flows into the fracture, the loss of wellbore fluid may cause the hydrostatic pressure in the wellbore to decrease, which may in turn also allow formation fluids to enter the wellbore. As a result, the formation fracture pressure typically defines an upper limit for allowable wellbore pressure in an open wellbore while the pore pressure defines a lower limit. Therefore, a major constraint on well design and selection of drilling fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients though the depth of the well.” [0028] “Specifically, the pressure within the loss zone may calculated as follows: […] Dz is the true vertical depth (TVD) of the loss zone (m))” [0052] “In alternate embodiments, a drilling engineer may check for fluid loss (ST100) at selected depth intervals. In such an embodiment, a check for fluid loss (ST100) may occur, for example, in 25, 50, or 100 foot increments. In still other operations, a drilling engineer may check for fluid loss (ST100) when drilling switches between formation types or only when fluid volume loss is reported. Those of ordinary skill in the art will appreciate that offset well data may be used to predict areas that may result in fluid loss, and in such locations, more frequent fluid loss checks (ST100) may be performed.”)
generating a fluid loss control treatment by particle type iteration, comprising;
selecting a first particle type from an inventory of particle types; (Loe [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity value is better than expected/no longer exceeds a threshold for the use of the particle, e.g., a large particle. [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid – a first particle type is selected from an inventory of particles.)
determining, by a particle model, a first value of a filter property at the fracture location resulting from treatment with the first particle type, wherein the filter property is a porosity value, a permeability value, or combinations thereof; (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid, as well as determining a rate of LCM addition to the fluid. After the amount of LCM required to continue the preventative treatment is determined (ST408),” [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity based on treatment with a first particle.)
determining whether the first value of the filter property exceeds a threshold; (Loe [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity value is better than expected/no longer exceeds a threshold or is the wrong type of the size or shape of the pores of the remaining fracture for the use of the particle, e.g., a large particle.)
selecting a second particle type from the inventory of particle types, in response to determining that the first value of the filter property does not exceed the threshold; (Loe [0060] “After one of blends (ST106 a-c) is pumped downhole (i.e., the solution is implemented), the drilling engineer determines whether the blend was successful (ST109) in resolving the fluid loss. If the fluid loss is resolved, the drilling engineer may continue to drill ahead (ST101). However, if the blend did not resolve the fluid loss, the drilling engineer determines whether the measured rate of loss (ST105) is the same, has decreased, or has increased. If the measured rate of loss has remained the same, or is still classified as a seepage loss (ST106), the drilling engineer may repeat the selection of a blend, including either re-pumping the same blend, or selecting a new blend within the matrix.” – If one treatment does not work, the engineer consults the rubric to see if another will work. [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity value is better than expected/no longer exceeds a threshold for the use of the particle, e.g., a large particle. [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid – The new solution is made with a new particle based on determining that such a large particle is not needed for porosity below a threshold for that particle.)
determining, by the particle model, a second value of the filter property at the fracture location resulting from treatment with the second particle type; (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid, as well as determining a rate of LCM addition to the fluid. After the amount of LCM required to continue the preventative treatment is determined (ST408),” [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity based on treatment with a second particle.)
determining whether the second value of the filter property exceeds the threshold; and (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid – The new solution with the new particle is determined to meet the porosity threshold (e.g., a correct particle type to deal with that porosity).)
generating, by the design process, the fluid loss control treatment based on the second particle type and a concentration of the second particle type to form at the interface, in response to determining that the second value of the filter property exceeds the threshold, generating, by the design process, the fluid loss control treatment based on the second particle type and a concentration of the second particle type to format the interface, in response to determining that the second value of the filter property exceeds the threshold, (Loe [0036] “For low fluid loss, particle-based treatments, a treatment blend solution may be based on a particle size distribution that follows the Ideal Packing Theory is designed to minimize fluid loss. Further discussion of selection of particle sizes required to initiate a bridge may be found in SPE 58793, which is herein incorporated by reference in its entirety. In order to achieve plugging or bridging, a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture” [0057] “As illustrated, for a seepage loss (ST106), a drilling engineer may be presented with several solutions for a loss control material to pump downhole, in this embodiment Blend #1 (ST106 a), Blend #2 (ST106 b), and Blend #3 (ST106 c). Each blend may be pre-selected as an appropriate blend for a rate of loss classified as a seepage loss (ST106). For example, in one embodiment, blends (ST106 a-c) may include a plurality of blends selected based on a determined fracture width and the type of fluid being used. In one embodiment, Blend #1 (ST106 a) may include a blend of loss control material selected to seal fractures up to 1000 μm, while Blend #2 (ST106 b) may include a blend of loss control material selected to seal fractures up to 1500 μm. In such an embodiment, Blend #3 (ST106 c) may be selected to include an alternate blend of loss control material capable of sealing fractures of up to 150 μm.” – Having determined the particle type satisfies the threshold (e.g., a particle type to plug a certain fracture), a new fluid treatment is created with the particle type.)
wherein the particle-laden fluid is pumped into a wellbore according to the generated fluid loss control treatment. (Loe [0044] “The term “settable fluid” as used herein refers to any suitable liquid material which may be pumped or emplaced downhole, and will harden over time to form a solid or gelatinous structure and become more resistance to mechanical deformation.” [0045] “Formation, pumping, and setting of a cement slurry is known in art, and may include the incorporation of cement accelerators, retardants, dispersants, etc., as known in the art, so as to obtain a slurry and/or set cement with desirable characteristics. “Gunk” as known in the art refers to a LCM treatment including pumping bentonite (optionally with polymers or cementious materials” [00560 “For a seepage loss (ST106), the options for solving the fluid loss may include pumping one or more loss control blends (in this embodiment, one selected from three choices) downhole.”) which will harden upon exposure to water to form a gunky semi-solid mass, which will reduce lost circulation.” [0060] “After one of blends (ST106 a-c) is pumped downhole (i.e., the solution is implemented), the drilling engineer determines whether the blend was successful (ST109) in resolving the fluid loss. If the fluid loss is resolved, the drilling engineer may continue to drill ahead (ST101). However, if the blend did not resolve the fluid loss, the drilling engineer determines whether the measured rate of loss (ST105) is the same, has decreased, or has increased. If the measured rate of loss has remained the same, or is still classified as a seepage loss (ST106), the drilling engineer may repeat the selection of a blend, including either re-pumping the same blend, or selecting a new blend within the matrix.” – The treatments are pumped down the wellbore.)
Loe suggests (Loe [0055] “The measured rate of fluid loss (ST105) may thus include calculating the fluid loss rate at the drilling location. As described in detail above, the rate of fluid loss (ST103) may be classified based on a rate of fluid loss in cubic meters lost per hour.” [0085] “HTHP test devices typically include a container including a disc, such as a perforated ceramic disc, whereby a sample of the drilling fluid procured from the return flow of drilling fluid is placed into the container under a specified temperature and pressure, and then the amount of fluid passing through the disc is measured. Based on the amount of fluid that passed through the disc, the fluid loss downhole may be estimated.”) but does not appear to explicitly teach, but Chang teaches,
retrieving, by a design process executing on a computer system, a drilling dataset for at least one offset well proximate to a new wellsite, and wherein the computer system comprises a non-transitory memory and a processor; determining, by a hydraulic fluid model, a fluid loss rate by inputting the drilling dataset into the hydraulic fluid model; (Chang Page 173, Right Column, Last Paragraph “The associated fluid-loss rate is
q
t
=
S
∆
p
t
-
1
/
2
2
)” See also other developed fluid loss equations A-13, A-14, and A-18 on Page 174.” – Chang uses a measured pressure difference
∆
p
, which relies on a pressure in the borehole, an element of the at least one dataset.)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the determination of a fluid loss rate as an intermediate value for determining a fluid loss treatment of Loe by the specific equation for fluid loss determined based on measured pressure differences for determining fluid loss treatment properties in Chang because a person of ordinary skill in the art would be motivated, based on the expressed aim to determine particle sizes in a fluid loss mud based on formation pressures and fluid loss rates in Loe, to look to Chang for dynamic systems that are useful to aid in the planning, understanding, and interpretation (e.g., via fluid loss rates) of formation-pressure measurements while drilling. (Loe [0024] “A particularly challenging situation arises in depleted reservoirs, in which high pressured formations are neighbored by or inter-bedded with normally or abnormally pressured zones.” [0034] “The result of the type, quantification, and analysis of losses, formation/fracture type, and pressures within the loss zone may be then used to decide the type of curing method to be used.” [0039] “LCM treatments may include particulate- and/or settable-based treatments. The various material parameters that may be selected may include 1) material type in accordance with considerations based on drilling fluid compatibility, rate of fluid loss, fracture width, and success of prior treatments, etc., 2) the amount of treatment materials, in accordance with the measured or anticipate rate of fluid loss, and 3) particle size and particle size distribution, in accordance with pressure levels, formation type, fracture width, etc.” [0042] “However, the fracture width may be dependent, amongst other factors, upon the strength (stiffness) of the formation rock and the extent to which the pressure in the wellbore is increased to above initial fracture pressure of the formation during the fracture induction (in other words, the fracture width is dependent on the pressure difference between the drilling mud and the initial fracture pressure of the formation during the fracture induction step).”; Chang Page 1, Summary “A model is described that is capable of simulating in detail the time variation of formation pressures measured while drilling, in situations where supercharging is significant. Simulation results illustrate the variation of supercharging pressures with formation permeability, drilling-fluid-filtration properties, and drilling-fluid hydraulics. The model is used to explore how drilling operations influence the levels of supercharging when drilling two formations, widely separated along the well trajectory, and of significantly different permeabilities. The forward-simulation capability presented is believed to be a useful aid to the planning, understanding, and interpretation of formation-pressure measurements while drilling.” Also, see the relationships between formation pressures and fluid loss rates in equations A-13 and A-14 on page 174)
While Loe and Chang do not appear to explicitly teach the following feature, Loe and Chang in view of Chevron teaches,
designing, by the design process, a fluid loss control treatment comprising quantity of particles and a volume of carrier fluid for forming an interface at a fracture location within a wellbore of the new wellsite. (Chevron Pages 32-33 THE BENTONITE-DIESEL OIL (BDO) OR BENTONITE-SYNTHETIC OIL (BSO) SLURRY AND SQUEEZE IN WATER BASED DRILLING FLUIDS “Formula: 1. 300-400 pounds bentonite 2.1 bbl of diesel oil, mineral oil or synthetic oil (final volume 1.42 bbl) 3. Lost circulation material optional at 10-12 ppb. 4. Barite as needed for density Squeeze Procedure: 1. Locate loss zone and run in hole open ended. Ideally, the loss zone should be known so the BDO can be placed efficiently where needed. If hole conditions allow place the pipe just above the loss zone, if not place the end of the pipe inside the casing. 2. Determine the volume of slurry to pump. Typically, a 40 barrel pill is used. It is advisable to mix in 10 bbl increments as to provide easier cleanup of the pumping equipment. 3. Pump a 5-10 bbl base oil spacer ahead and behind the slurry. 4. Pump pill to bottom of pipe and follow spacer with drilling fluid. 5. Close the blow out preventers. 6. Pump the slurry out the drill string at 1-2 bbl/minute and pump drilling fluid into annulus at 4-8 bbl/min for a thinner initial slurry pump at 8-16 bbl per minute down the annulus. 7. When one half the slurry from drill string is displaced; reduce pump rates to 1 bbl/min on the drill pipe and 1-3 bbl/min on the annulus. 8. When desired pressure is reached, maintain pressure on casing. Displace the drill string volume with drilling fluid and pull into casing. 9. Maintain pressure on the well for approximately 3 hours. 10.Circulate and condition the drilling fluid in the casing, and wash and ream the open hole slowly to bottom. This avoids pushing the bit into the BDOslurry and possibly pressuring up the hole causing lost circulation to reoccur. Note: As the BDO pill is circulated to the surface the shale shaker may blind and should be closely watched to prevent mud losses across the screens. BDO pills are not incorporated into the drilling fluid and are not saved for future use! Do not attempt to reverse out unused BDO, as the pipe is likely to become plugged!)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the high-level descriptions of fluid loss control treatments in Loe by the specific pump procedures and LCM mixtures of Chevron because a person of ordinary skill in the art would be motivated based on the desire to optimize fluid loss control treatments expressed in Loe using the specific blends in Chevron that can bring a dysfunctional/leaking well back to operation with the benefit of 180 years of total experience in the methods. (Loe [0003] “Embodiments disclosed herein relate generally to lost circulation experienced during drilling a wellbore. In particular, embodiments disclosed herein relate to the detection, classification, and remedial treatment of lost circulation occurrences. Additionally, embodiments disclosed herein also relate to the anticipation of lost circulation during wellbore planning and preventative treatments to minimize the occurrences of such lost circulation.” [0029] “Additionally, the severity may also be classified by the rate at which the fluid is being lost. Specifically, loss rates may be classified into general categories of seepage loss (less than 3 m3/hr), partial loss (3-10 m3/hr) where some fluid is returned to the surface, and severe to total loss (greater than 10 m3/hr) where little or no fluid is returned to the surface through the annulus.”; Chevron Page 4, LOSS OF CIRCULATION FOREWARD “In a broad survey conducted by Drilling Specialties Company loss of circulation was identified as the most costly problem faced by the oil and gas industry associated with drilling fluids. The purpose of this CD is to inform the reader of the nature of this problem and ways to solve it. This CD was prepared by a team of individuals that combined have over 180 years’ experience in the drilling fluids business.”)
Claim 21
Regarding claim 21, Loe, Chang, and Chevron teach the features of claim 1 and further teach:
wherein the generating of the fluid loss control treatment further comprises iterating a fluid property, wherein the fluid property comprises fluid density or fluid rheology. (Loe [0074] “An alternative consideration that may be factored into the pre-selected blends is the type of fluid being used, for example, water-based or oil-based drilling fluids. As such, in one embodiment, Blend #3 (ST206 c) may be a blend optimized for oil-based drilling fluids, while Blend #2 (ST206 b) is optimized for water-based drilling fluids. Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient. The solution may also be selected based on secondary considerations known to those of ordinary skill in the art.” [0058] “In select embodiments, a drilling engineer may predict or estimate the fracture width of a segment of the wellbore, for example the risk zone, where fluid loss is believed to be occurring. The predicting may include using drilling or wellbore parameters and rock properties to determine an estimated fracture width, as described above. After the fracture width is predicted, optimal solution parameters, as well as optimal drilling fluid parameters for drilling ahead, based on the predicted fracture width may be determined. Examples of solution parameters may include loss control material size and concentration, while examples of drilling fluid parameters may include density, viscosity, rheology, and flow rate. In still other embodiments, predicting the fracture width may include using a rate of fluid loss and a hydraulic pressure in the loss zone to calculate the fracture width.” – The iteration of different solutions with different properties is mapped in independent claim 1. This teaches iterating the type of fluid used based on fluid properties, including density and rheology.)
Claims 3-4: Loe, Chang, Chevron, and Majidi
Claims 3-4 rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over US 2009/0188718 A1 to Kaageson-Loe et al. (Loe) in view of NPL: “When Should We Worry About Supercharging in Formation-Pressure-While-Drilling Measurements?” by Chang et al. (Chang), NPL: “Loss Circulation Guide” by Chevron. (Chevron), , and NPL: “Fingerprint of Mud Losses into Natural or Induced Fractures” by Majidi et al. (Majidi).
Regarding claim 3, Loe, Chang, Chevron, and Majidi teach:
determining, by a formation fracture model, a fracture type, the fracture geometry, or combinations thereof by inputting the fluid loss rate, the at least one dataset, or combinations thereof into the formation fracture model. (Majidi Page 9 “Induced versus Natural fractures Let us make a comparison between analytical formulation of induced fracture and natural fractures. Eq. 19 and Eq. 20 are derived for the steady state flow rate of losses in an induced and a natural pre-existing fracture, respectively. Note that rf in Eq. 19 represents radial extension of the fracture while rf in Eq. 20 represents the radius of the mud invasion (mud front) within a pre-existing natural fracture. ” Page 10, Second Paragraph “The pressure sensitivity of the rate of losses in induced and natural fractures can be used as an effective indication to distinguish between natural and induced fractures. Once the fracture type is identified, the fracture parameters (i.e., width or stiffness) can be determined from analysis of mud loss data by finding the best match between mud loss predictions and measurements. Synthetic data were generated to show the differences between rate-pressure response of natural and induced fractures. An arbitrary over-pressure fluctuation was considered (Fig.20) to create an induced fracture. A 15% deviation from the exact response is applied to mimic the measurement error in mud loss rates. Mud loss flow rates behavior of a natural and an induced fracture under the imposed pressure fluctuations are demonstrated in Fig. 20. Results show that if there is enough pressure fluctuation at the wellbore, the associated mud loss behavior will be quite distinct in natural and induced fractures. A 20% fluctuation in wellbore pressure (which is very common due to partial loss of the fluid in the well or the drop of fluid level below the surface) will be sufficient to distinguish between losses into natural fractures from induced fractures. Under an identical pressure fluctuation, the high pressure sensitivity of mud losses in an induced fracture becomes evident while mud losses in natural fractures will behave more smoothly when compare to those in induced fractures. The very distinct responses of mud losses prove that it is very unlikely to confuse induced fractures with natural fractures (or vice versa) by looking into the simulated behavior and comparisons of mud loss predictions, given the accurate measurements of mud losses and downhole pressure.” Page 11, Conclusions, Third Bullet Point “The type of fractures can be identified by the difference between pressure sensitivity of mud losses in induced and natural fracture. Once the fracture type is determined, the fracture parameters (hydraulic width or compliance) can be estimated by analysis of mud losses history using the provided model. The analysis of mud losses methods gives the fracture properties within a large volume of rock and is of more representative of the real scale compare with logging techniques that are localized around the wellbore.”)
PNG
media_image4.png
375
913
media_image4.png
Greyscale
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to assess the fracture in Loe using the fracture modeling of Majidi because a person of ordinary skill in the art would be motivated based on the expressed aim to control fluid loss by selecting LCM treatments based on fracture width or formation/fracture type in Loe, to look to Majidi which provides guidelines for the best practices to be used for prevention and control of lost circulation based on identifying fracture width and type. (Loe [0039] “LCM treatments may include particulate- and/or settable-based treatments. The various material parameters that may be selected may include 1) material type in accordance with considerations based on drilling fluid compatibility, rate of fluid loss, fracture width, and success of prior treatments, etc., 2) the amount of treatment materials, in accordance with the measured or anticipate rate of fluid loss, and 3) particle size and particle size distribution, in accordance with pressure levels, formation type, fracture width, etc.”; Majidi Abstract “Lost circulation in fractured formations is one of the drilling's biggest expenses in terms of non-productive time (NPT), unit mud cost and safety issues. The severity and persistence of losses are to a large extent determined by the type of formation into which the fluid is being lost. It is imperative to identify whether the losses are to natural or induced fractures as losses into naturally fractured rocks require different treatments than those into drilling induced fractures. One way of identifying the type of the fracture is by image logs which are very local and limited to conductive muds, so still in their infancy and have yet to gain wide acceptance. An alternative way is possible by looking into flow behavior of mud losses (flow in/out) and associated downhole pressure response (PWD data). This work presents an analytical formulation describing mud losses in drilling induced fractures based on which the volume and rate of losses in an induced fracture are quantified in terms of fluid properties, fracture parameters and operational conditions. Comparison between the predicted mud losses into induced and natural fractures indicates that much higher pressure sensitivity is anticipated during mud losses into induced fractures. Hence, the pressure sensitivity analysis can be used as a means to distinguish between the losses into natural and induced fractures. Once the fracture type is identified, the fracture parameters (hydraulic width or compliance) can be estimated by analyzing mud loss data. As the outcome of this study, guidelines are provided for the best practices to be used for prevention and control of lost circulation.”)
Regarding claim 4, Loe, Chang, Chevron, and Majidi teach:
wherein the formation fracture model calculates a fracture as one of a group selected from a natural fracture, an induced fracture, or a highly permeable zone. (Majidi Page 9 “Induced versus Natural fractures Let us make a comparison between analytical formulation of induced fracture and natural fractures. Eq. 19 and Eq. 20 are derived for the steady state flow rate of losses in an induced and a natural pre-existing fracture, respectively. Note that rf in Eq. 19 represents radial extension of the fracture while rf in Eq. 20 represents the radius of the mud invasion (mud front) within a pre-existing natural fracture. ” Page 10, Second Paragraph “The pressure sensitivity of the rate of losses in induced and natural fractures can be used as an effective indication to distinguish between natural and induced fractures. Once the fracture type is identified, the fracture parameters (i.e., width or stiffness) can be determined from analysis of mud loss data by finding the best match between mud loss predictions and measurements. Synthetic data were generated to show the differences between rate-pressure response of natural and induced fractures. An arbitrary over-pressure fluctuation was considered (Fig.20) to create an induced fracture. A 15% deviation from the exact response is applied to mimic the measurement error in mud loss rates. Mud loss flow rates behavior of a natural and an induced fracture under the imposed pressure fluctuations are demonstrated in Fig. 20. Results show that if there is enough pressure fluctuation at the wellbore, the associated mud loss behavior will be quite distinct in natural and induced fractures. A 20% fluctuation in wellbore pressure (which is very common due to partial loss of the fluid in the well or the drop of fluid level below the surface) will be sufficient to distinguish between losses into natural fractures from induced fractures. Under an identical pressure fluctuation, the high pressure sensitivity of mud losses in an induced fracture becomes evident while mud losses in natural fractures will behave more smoothly when compare to those in induced fractures. The very distinct responses of mud losses prove that it is very unlikely to confuse induced fractures with natural fractures (or vice versa) by looking into the simulated behavior and comparisons of mud loss predictions, given the accurate measurements of mud losses and downhole pressure.” Page 11, Conclusions, Third Bullet Point “The type of fractures can be identified by the difference between pressure sensitivity of mud losses in induced and natural fracture. Once the fracture type is determined, the fracture parameters (hydraulic width or compliance) can be estimated by analysis of mud losses history using the provided model. The analysis of mud losses methods gives the fracture properties within a large volume of rock and is of more representative of the real scale compare with logging techniques that are localized around the wellbore.”)
Claim 8, 12, 14, and 15: Loe, Chang, and Hommel
Claims 8,12, 14, and 15 are rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over US 2009/0188718 A1 to Kaageson-Loe et al. (Loe) in view of NPL: “When Should We Worry About Supercharging in Formation-Pressure-While-Drilling Measurements?” by Chang et al. (Chang), and NPL: “Porosity-Permeability Relations for Evolving Pore Space: A Review with a Focus on (Bio-)geochemically Altered Porous Media” by Hommel et al. (Hommel).
Regarding claim 8, Loe and Chang teach the features of claim 1. Loe and Chang fail to teach, but Hommel teaches
wherein the particle model utilizes an equation for determining the porosity value of the interface:
PNG
media_image1.png
95
327
media_image1.png
Greyscale
wherein D represents an average particle diameter; ϵ represents an estimated porosity based on empirical results; and φ represents a sphericity of the particle type forming the interface. (Hommel, Page 593, Last Paragraph – Top of Page 594 and Equation 9 “A second widely used approach is the Kozeny–Carman equation, which was originally published in Kozeny (1927) and was later modified in Carman (1937) to calculate the pressure difference, Δp, required for fluid flow at the velocity, v, through a particle packing of the length, L. […] where
Φ
s is the sphericity, a dimensionless particle geometry parameter, Dp [m] is the characteristic particle diameter, and Φ [−] is the porosity. Equation (8) can be reformulated using Darcy’s Law, see Eq. (6), to estimate the permeability according to Kozeny and Carman, KKC, in m2 directly:
K
K
C
=
Φ
S
2
D
p
2
180
Φ
3
(
1
-
Φ
)
2
” - Equation (9) in Hommel is an obvious variant of the equation in claim 8, because the constant denominator in the reference is 180 rather than the 150 in the claim. However,
Φ
s, the sphericity, is a dimensionless unit and is definable to be of different magnitudes, even by a factor of the square root of 1.2. Accordingly, the features of claim 8 are obvious in view of Equation (9) in Hommel.
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the determination of porosity/permeability in Loe with Equation 9 of Hommel because Loe determines whether to adjust the LCM treatment based on formation porosity, and Hommel demonstrates essential features of methods for assessing dynamic porosity changes. (Loe [0087] “Reviewing the LCM formulation with respect to the formation properties (ST226) may include determining the formation porosity, permeability, lithology, and particle size distribution. Such properties may be determined by use of measurement while drilling and/or logging while drilling tools, as well as mud log data, that is typically available at the drilling rig site. After determining the formation properties, the LCM formulation may be adjusted (ST227) to decrease the reservoir fluid loss. After the formulation adjustment (ST227), the fluid loss may be remeasured (ST225), and additional determinations of increasing the LCM concentration may occur (ST221) or the LCM blend may be reformulated (ST226) if the fluid loss is not within an acceptable range.“; Hommel Abstract “Other exceptions are relations that consider a critical porosity at which the porous medium becomes impermeable; this is often used when modeling the effect of mineral precipitation. This review first defines the scale on which porosity–permeability relations are typically used and aims at explaining why these relations are not unique. It shows the variety of existing approaches and concludes with their essential features.” Page 593, Last Paragraph to Page 594 Top of Page “Equation (8) can be reformulated using Darcy’s Law, see Eq. (6), to estimate the permeability according to Kozeny and Carman, KKC, in m2 directly:
K
K
C
=
Φ
S
2
D
p
2
180
ϕ
3
(
1
-
ϕ
)
2
”)
Regarding claim 12, Loe teaches:
A computer-implemented method of designing a fluid loss control treatment with real-time pumping data, comprising: (Loe [0013] “In another aspect, embodiments disclosed herein relate to a method for treating drilling fluid loss at a drilling location, the method including calculating a drilling fluid loss rate at the drilling location, classifying the drilling fluid loss based on the drilling fluid loss rate or pressure in the loss zone, and selecting a solution based at least in part on the classifying.” – This is a method of designing a wellbore fluid treatment.; [0114] “Embodiments of the invention may be implemented on virtually any type of computer regardless of the platform being used.” – These methods are computer-implemented. [0068] “In this embodiment, a drilling engineer evaluates the drilling operation to determine whether the operation is losing fluid while drilling (ST200).” – Monitoring of pumping data is done in real-time. With respect to the computer implementation of steps, even if a person of ordinary skill in the art would interpret the steps as being conducted manually, e.g., by an engineer, rather than a computer in the references cited, MPEP 2111 and MPEP 2144.04(III) show that a person of ordinary skill in the art would find it obvious to automate the steps of the references using a computer because a computer would do so faster. This is simply automating of what might be a manual activity using a computer, which is obvious in light of In re Prater.)
receiving, by a design process executing on a processor, at least one real-time dataset associated with a pumping equipment fluidically connected to a wellbore, wherein the at least one real-time dataset comprises a dataset selected from the group consisting of drilling equipment dataset, bottom hole assembly (BHA) dataset, fluid system dataset, or combination thereof; determining, by the processor, a fluid loss rate fLoe [0090] “Planning the wellbore may initially include defining drilling data for drilling at least a segment of a planned wellbore. The segment may include, for example, a predetermined length, a specific formation, a time period, and a wellbore depth. Drilling data may include any data that may be used to plan wellbores, such as wellbore lithology, porosity, tectonic activity, fracture gradient, fluid type, fluid properties, hydraulic pressure, fluid composition, well path, rate of penetration, weight on bit, torque, trip speed, bottom hole assembly design, bit type, drilling pipe size, drill collar size, and casing location. Drilling data may include offset well data, experience data collected from similar drilling operations, or data such as that collected during prior remedial treatment operations.” [0028] “Further, the severity of the fluid loss will be related to the cause of the lost circulation, and may be characterized by the pressure within the loss zone and by the rate of fluid loss. The pressure in the loss zone can be estimated based, in part, on the fluid volume added to top-off the well, i.e., the fluid volume required to re-fill the well. Specifically, the pressure within the loss zone may calculated as follows” [0055] ” If the fluid loss is not determined to be a surface loss (ST103), thereby resulting in a no condition, the drilling engineer should proceed with measuring the rate of fluid loss (ST105). The measured rate of fluid loss (ST105) may thus include calculating the fluid loss rate at the drilling location. As described in detail above, the rate of fluid loss (ST103) may be classified based on a rate of fluid loss in cubic meters lost per hour. As illustrated, in this embodiment, the fluid loss is classified as either a seepage loss (ST106), a partial loss (ST107), or a severe/total loss (ST108). As described above, seepage losses include losses less than three cubic meters per hour, while partial losses include loses from three to ten cubic meters per hour, and severe/total losses are losses of greater than 10 cubic meters per hour.” – Data from the worksite is used to determine fluid loss.)
determining, by the design process, a fracture location within the wellbore; (Loe [0023] “Alternatively, lost circulation may be the result of drilling-induced fractures. For example, when the pore pressure (the pressure in the formation pore space provided by the formation fluids) exceeds the pressure in the open wellbore, the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is typically maintained at a higher pressure than the pore pressure. While it is highly advantageous to maintain the wellbore pressures above the pore pressure, on the other hand, if the pressure exerted by the wellbore fluids exceeds the fracture resistance of the formation, a formation fracture and thus induced mud losses may occur. Further, with a formation fracture, when the wellbore fluid in the annulus flows into the fracture, the loss of wellbore fluid may cause the hydrostatic pressure in the wellbore to decrease, which may in turn also allow formation fluids to enter the wellbore. As a result, the formation fracture pressure typically defines an upper limit for allowable wellbore pressure in an open wellbore while the pore pressure defines a lower limit. Therefore, a major constraint on well design and selection of drilling fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients though the depth of the well.” [0028] “Specifically, the pressure within the loss zone may calculated as follows: […] Dz is the true vertical depth (TVD) of the loss zone (m))” [0052] “In alternate embodiments, a drilling engineer may check for fluid loss (ST100) at selected depth intervals. In such an embodiment, a check for fluid loss (ST100) may occur, for example, in 25, 50, or 100 foot increments. In still other operations, a drilling engineer may check for fluid loss (ST100) when drilling switches between formation types or only when fluid volume loss is reported. Those of ordinary skill in the art will appreciate that offset well data may be used to predict areas that may result in fluid loss, and in such locations, more frequent fluid loss checks (ST100) may be performed.”)
generating a fluid loss control treatment by particle type iteration, comprising: selecting a first particle type from an inventory of particle types; (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid – The new is made with a first particle.)
determining, by a particle model, a first value of a filter property at the fracture location resulting of treatment with the first particle type, wherein the filter property is a porosity value, a permeability value, or combinations thereof; (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid, as well as determining a rate of LCM addition to the fluid. After the amount of LCM required to continue the preventative treatment is determined (ST408),” [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity based on treatment with a first particle.)
determining whether the first value of the filter property exceeds a threshold; (Loe [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity value is better than expected/no longer exceeds a threshold for the use of the particle, e.g., a large particle.)
selecting a second particle type from the inventory of particle types, in response to determining that the first value of the filter property does not exceed the threshold; (Loe [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity value is better than expected/no longer exceeds a threshold for the use of the particle, e.g., a large particle. [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid – The new solution is made with a new particle based on determining that such a large particle is not needed for porosity below a threshold for that particle.)
determining, by the particle model, a second value of the filter property at the fracture location resulting from treatment with the second particle type; (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid, as well as determining a rate of LCM addition to the fluid. After the amount of LCM required to continue the preventative treatment is determined (ST408),” [0107] “If, based on the review of the solids control management, the drilling operator determines that additional medium or coarse LCM solids are not needed (ST413), then the LCM blend may be reviewed with respect to the formation properties (ST417). The reviewed properties may include, for example, the formation porosity, permeability, lithology, and particle size distribution. With the updated formation properties and LCM blend review (ST417), the maintenance of the LCM may be recalculated (ST408).” – The engineer determines a porosity based on treatment with a second particle.)
determining whether the second value of the filter property exceeds the threshold; and (Loe [0036] “In order to achieve plugging or bridging [example of an operational objective], a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake [example of an interface; see [0063]: “This interface, also referred to as filter cake,…”] behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture.” [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate.” [0059] “Those of ordinary skill in the art will appreciate that the matrix of blend options and the specific fracture apertures for which the blends are optimized may vary according to specific parameters of the drilling operation. As such, a drilling engineer may optimize the blend matrix for a particular drilling operation by including blends that would resolve fluid loss recorded in, for example, offset wells. The specific solution selected for a particular drilling operation may be based at least in part on a severity of the loss, the type of drilling fluid used, the type of formation being drilling, the type and size of fracture, and the fracture gradient.” [0104] “The maintenance calculation may include determining the concentration of medium and/or coarse LCM solids in the fluid – The new solution with the new particle is determined to meet the porosity threshold (e.g., a correct particle type to deal with that porosity).)
generating, by the design process, the fluid loss control treatment based on the second particle type and a concentration of the second particle type to form at the interface, in response to determining that the second value of the filter property exceeds the threshold, (Loe [0036] “For low fluid loss, particle-based treatments, a treatment blend solution may be based on a particle size distribution that follows the Ideal Packing Theory is designed to minimize fluid loss. Further discussion of selection of particle sizes required to initiate a bridge may be found in SPE 58793, which is herein incorporated by reference in its entirety. In order to achieve plugging or bridging, a particulate treatment may be selected based on particle type(s), particle geometry(s), concentration(s), and particle size distribution(s) so that coarse or very coarse particles plug or bridge the mouth of the fracture (or the oversized pores of the high permeability formation), and finer particles may then form a tight filtercake behind the bridging particles, thus affecting a seal and fluid loss control. However, in addition to such particulate based treatments, depending on the classified severity of loss, a reinforcing plug, including cement- or resin-based plugs, may be necessary to seal off the fracture” [0057] “As illustrated, for a seepage loss (ST106), a drilling engineer may be presented with several solutions for a loss control material to pump downhole, in this embodiment Blend #1 (ST106 a), Blend #2 (ST106 b), and Blend #3 (ST106 c). Each blend may be pre-selected as an appropriate blend for a rate of loss classified as a seepage loss (ST106). For example, in one embodiment, blends (ST106 a-c) may include a plurality of blends selected based on a determined fracture width and the type of fluid being used. In one embodiment, Blend #1 (ST106 a) may include a blend of loss control material selected to seal fractures up to 1000 μm, while Blend #2 (ST106 b) may include a blend of loss control material selected to seal fractures up to 1500 μm. In such an embodiment, Blend #3 (ST106 c) may be selected to include an alternate blend of loss control material capable of sealing fractures of up to 150 μm.” – Having determined the particle type satisfies the threshold (e.g., a particle type to plug a certain fracture), a new fluid treatment is created with the particle type.)
wherein the particle-laden fluid is pumped into a wellbore according to the generated fluid loss control treatment. (Loe [0044] “The term “settable fluid” as used herein refers to any suitable liquid material which may be pumped or emplaced downhole, and will harden over time to form a solid or gelatinous structure and become more resistance to mechanical deformation.” [0045] “Formation, pumping, and setting of a cement slurry is known in art, and may include the incorporation of cement accelerators, retardants, dispersants, etc., as known in the art, so as to obtain a slurry and/or set cement with desirable characteristics. “Gunk” as known in the art refers to a LCM treatment including pumping bentonite (optionally with polymers or cementious materials” [00560 “For a seepage loss (ST106), the options for solving the fluid loss may include pumping one or more loss control blends (in this embodiment, one selected from three choices) downhole.”) which will harden upon exposure to water to form a gunky semi-solid mass, which will reduce lost circulation.” [0060] “After one of blends (ST106 a-c) is pumped downhole (i.e., the solution is implemented), the drilling engineer determines whether the blend was successful (ST109) in resolving the fluid loss. If the fluid loss is resolved, the drilling engineer may continue to drill ahead (ST101). However, if the blend did not resolve the fluid loss, the drilling engineer determines whether the measured rate of loss (ST105) is the same, has decreased, or has increased. If the measured rate of loss has remained the same, or is still classified as a seepage loss (ST106), the drilling engineer may repeat the selection of a blend, including either re-pumping the same blend, or selecting a new blend within the matrix.” – The treatments are pumped down the wellbore.)
While Loe does not appear to explicitly teach the following feature (Loe [0055] “The measured rate of fluid loss (ST105) may thus include calculating the fluid loss rate at the drilling location. As described in detail above, the rate of fluid loss (ST103) may be classified based on a rate of fluid loss in cubic meters lost per hour.” [0085] “HTHP test devices typically include a container including a disc, such as a perforated ceramic disc, whereby a sample of the drilling fluid procured from the return flow of drilling fluid is placed into the container under a specified temperature and pressure, and then the amount of fluid passing through the disc is measured. Based on the amount of fluid that passed through the disc, the fluid loss downhole may be estimated.”), Loe in view of Chang teaches:
receiving, by a design process executing on a processor, at least one real-time dataset associated with a pumping equipment fluidically connected to a wellbore, wherein the at least one real-time dataset comprises a dataset selected from the group consisting of drilling equipment dataset, bottom hole assembly (BHA) dataset, fluid system dataset, or combination thereof; determining, by the processor, a fluid loss rate from the at least one real-time dataset; (Chang Page 173, Right Column, Last Paragraph “The associated fluid-loss rate is
q
t
=
S
∆
p
t
-
1
/
2
2
)” See also other developed fluid loss equations A-13, A-14, and A-18 on Page 174.” – Chang uses a measured pressure difference
∆
p
, which relies on a pressure in the borehole, an element of the at least one dataset.)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the determination of a fluid loss rate as an intermediate value for determining a fluid loss treatment of Loe by the specific equation for fluid loss determined based on measured pressure differences for determining fluid loss treatment properties in Chang because a person of ordinary skill in the art would be motivated, based on the expressed aim to determine particle sizes in a fluid loss mud based on formation pressures and fluid loss rates in Loe, to look to Chang for dynamic systems that are useful to aid in the planning, understanding, and interpretation (e.g., via fluid loss rates) of formation-pressure measurements while drilling. (Loe [0024] “A particularly challenging situation arises in depleted reservoirs, in which high pressured formations are neighbored by or inter-bedded with normally or abnormally pressured zones.” [0034] “The result of the type, quantification, and analysis of losses, formation/fracture type, and pressures within the loss zone may be then used to decide the type of curing method to be used.” [0039] “LCM treatments may include particulate- and/or settable-based treatments. The various material parameters that may be selected may include 1) material type in accordance with considerations based on drilling fluid compatibility, rate of fluid loss, fracture width, and success of prior treatments, etc., 2) the amount of treatment materials, in accordance with the measured or anticipate rate of fluid loss, and 3) particle size and particle size distribution, in accordance with pressure levels, formation type, fracture width, etc.” [0042] “However, the fracture width may be dependent, amongst other factors, upon the strength (stiffness) of the formation rock and the extent to which the pressure in the wellbore is increased to above initial fracture pressure of the formation during the fracture induction (in other words, the fracture width is dependent on the pressure difference between the drilling mud and the initial fracture pressure of the formation during the fracture induction step).”; Chang Page 1, Summary “A model is described that is capable of simulating in detail the time variation of formation pressures measured while drilling, in situations where supercharging is significant. Simulation results illustrate the variation of supercharging pressures with formation permeability, drilling-fluid-filtration properties, and drilling-fluid hydraulics. The model is used to explore how drilling operations influence the levels of supercharging when drilling two formations, widely separated along the well trajectory, and of significantly different permeabilities. The forward-simulation capability presented is believed to be a useful aid to the planning, understanding, and interpretation of formation-pressure measurements while drilling.” Also, see the relationships between formation pressures and fluid loss rates in equations A-13 and A-14 on page 174)
While Loe and Chang appear to fail to explicitly teach the following feature, Loe and Chang in view of Hommel teaches:
wherein a filtration property of the fluid loss control treatment exceeds a threshold value, and wherein the filtration property is a porosity of the interface. (Hommel Page 610, Section 3.11 “The primary addition to this model in comparison to the Power Law is the critical porosity, φcrit , which is used to describe the nonzero porosity threshold at which the permeability asymptotically approaches zero. The critical porosity describes that not all pore space is effective for flow (see Sect. 2.4). The idea is that only for φ > φcrit , the pore space is connected and thus only the pore space exceeding this limit (φ − φcrit) contributes to flow, aiming at representing porous medium heterogeneities or disconnected pore space.”)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the fluid loss control treatment in Loe with the porosity considerations of the filter cake that results from the fluid loss control treatment in Hommel because Loe determines whether to adjust the LCM treatment based on formation porosity, and it would be obvious to try one of the recited applied porosity-permeability relations in simulation models in Hommel which represent pore structure morphology and related changes to flow parameters during these processes are critical when modeling reactive transport. Further, a person of ordinary skill in the art would be motivated to modify the adjustment of the LCM treatment of Loe using the any of the common methods recited in Hommel to account for porosity/permeability.
(Loe [0087] “Reviewing the LCM formulation with respect to the formation properties (ST226) may include determining the formation porosity, permeability, lithology, and particle size distribution. Such properties may be determined by use of measurement while drilling and/or logging while drilling tools, as well as mud log data, that is typically available at the drilling rig site. After determining the formation properties, the LCM formulation may be adjusted (ST227) to decrease the reservoir fluid loss. After the formulation adjustment (ST227), the fluid loss may be remeasured (ST225), and additional determinations of increasing the LCM concentration may occur (ST221) or the LCM blend may be reformulated (ST226) if the fluid loss is not within an acceptable range.“; Hommel Abstract “Reactive transport processes in a porous medium will often both cause changes to the pore structure, via precipitation and dissolution of biomass or minerals, and be affected by these changes, via changes to the material’s porosity and permeability. An understanding of the pore structure morphology and the changes to flow parameters during these processes is critical when modeling reactive transport [problem]. Commonly applied porosity–permeability relations in simulation models on the REV scale use a power-law relation, often with slight modifications, to describe such features [why to use these]; they are often used for modeling the effects of mineral precipitation and/or dissolution on permeability. To predict the reduction in permeability due to biomass growth, many different and often rather complex relations have been developed and published by a variety of authors. Some authors use exponential or simplified Kozeny-Carman relations. […] Other exceptions are relations that consider a critical porosity at which the porous medium becomes impermeable; this is often used when modeling the effect of mineral precipitation. This review first defines the scale on which porosity–permeability relations are typically used and aims at explaining why these relations are not unique. It shows the variety of existing approaches and concludes with their essential features.” Page 610, Section 3.11 “The primary addition to this model in comparison to the Power Law is the critical porosity, φcrit , which is used to describe the nonzero porosity threshold at which the permeability asymptotically approaches zero. The critical porosity describes that not all pore space is effective for flow (see Sect. 2.4). The idea is that only for φ > φcrit , the pore space is connected and thus only the pore space exceeding this limit (φ − φcrit) contributes to flow, aiming at representing porous medium heterogeneities or disconnected pore space.”)
Regarding claim 14, Loe, Chang, and Hommel teach:
determining, by a wellbore hydraulics model, the fluid loss rate by inputting the at least one dataset into the wellbore hydraulics model. (Chang Page 173, Right Column, Last Paragraph “The associated fluid-loss rate is
q
t
=
S
∆
p
t
-
1
/
2
2
)” See also other developed fluid loss equations A-13, A-14, and A-18 on Page 174.” – Chang uses a measured pressure difference
∆
p
, which relies on a pressure in the borehole, an element of the at least one dataset.)
Regarding claim 15, Loe, Chang, and Hommel teach the features of claim 12. Loe further teaches:
determining, by a formation fracture model, a fracture type, a fracture geometry, or combinations thereof by inputting the fluid loss rate, the at least one dataset, or combinations thereof into the formation fracture model. (Loe [0032] “The fracture width may either be calculated using drilling parameters and rock properties or estimated from the rate of fluid losses and the hydraulic pressure in the loss zone. For example, fracture gradient, Young's modulus, Poisson's ratio, well pressure, and hole size may be at least used to estimate the width of fractures, which may be done in pre-well planning or following loss occurrences. Such determinations may be made based on conventional fracture models known in the art, including modified Perkins-Kern-Nordgren (PKN) & Geertsma-de Klerk-Khristianovic (GdK) based fracture models.” – Models (e.g., fraction models) use the fluid loss rate or other elements of the data to determine fracture width (e.g., geometry).)
Claims 10-11: Loe, Chang, Chevron, and Heathman
Claims 10-11 are rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over US 2009/0188718 A1 to Kaageson-Loe et al. (Loe) in view of NPL: “When Should We Worry About Supercharging in Formation-Pressure-While-Drilling Measurements?” by Chang et al. (Chang), NPL: “Loss Circulation Guide” by Chevron. (Chevron), and NPL: “Finite Element Analysis Couples Casing and Cement Designs for HP/HT Wells in East Texas” by Heathman et al (Heathman).
Regarding claim 10, Loe, Chang, and Chevron Teach:
further comprising: transporting a a pumping equipment to a well site, (Loe, as demonstrated for the struckthrough elements above now in bold here, in view of Chevron Page 20 “Mixing Requirements: 1. Clean, isolated mixing tank or liquid mud plant 2. Cement pump truck needed if low volume pump rate required 3. Oil-wetting agent required to prevent excessive viscosity in weighted oil slurry 4. Pump through open ended pipe if additional LCM is added to slurry” The cement pump truck and mixing tank of mud plant are interpreted to be pumping equipment” – The pump truck is a mobile pumping equipment unit that would not merely exist at the site from the beginning of time. It requires humans to drive/transport it.)
mixing a fluid loss control treatment, by the pumping equipment, per the pumping procedure; and (Chevron Page 20 “Mixing Requirements: 1. Clean, isolated mixing tank or liquid mud plant 2. Cement pump truck needed if low volume pump rate required 3. Oil-wetting agent required to prevent excessive viscosity in weighted oil slurry 4. Pump through open ended pipe if additional LCM is added to slurry” - The cement pump truck and mixing tank of mud plant are interpreted to be pumping equipment, which mix the slurry.)
pumping the fluid loss control treatment per the pumping procedure. (Chevron Page 20 “Mixing Requirements: 1. Clean, isolated mixing tank or liquid mud plant 2. Cement pump truck needed if low volume pump rate required 3. Oil-wetting agent required to prevent excessive viscosity in weighted oil slurry 4. Pump through open ended pipe if additional LCM is added to slurry” Pages 32-33 THE BENTONITE-DIESEL OIL (BDO) OR BENTONITE-SYNTHETIC OIL (BSO) SLURRY AND SQUEEZE IN WATER BASED DRILLING FLUIDS “Formula: 1. 300-400 pounds bentonite 2. 1 bbl of diesel oil, mineral oil or synthetic oil (final volume 1.42 bbl) 3. Lost circulation material optional at 10-12 ppb. 4. Barite as needed for density Squeeze Procedure: 1. Locate loss zone and run in hole open ended. Ideally, the loss zone should be known so the BDO can be placed efficiently where needed. If hole conditions allow place the pipe just above the loss zone, if not place the end of the pipe inside the casing. 2. Determine the volume of slurry to pump. Typically, a 40 barrel pill is used. It is advisable to mix in 10 bbl increments as to provide easier cleanup of the pumping equipment. 3. Pump a 5-10 bbl base oil spacer ahead and behind the slurry. 4. Pump pill to bottom of pipe and follow spacer with drilling fluid. 5. Close the blow out preventers. 6. Pump the slurry out the drill string at 1-2 bbl/minute and pump drilling fluid into annulus at 4-8 bbl/min for a thinner initial slurry pump at 8-16 bbl per minute down the annulus. 7. When one half the slurry from drill string is displaced; reduce pump rates to 1 bbl/min on the drill pipe and 1-3 bbl/min on the annulus. 8. When desired pressure is reached, maintain pressure on casing. Displace the drill string volume with drilling fluid and pull into casing. 9. Maintain pressure on the well for approximately 3 hours. 10.Circulate and condition the drilling fluid in the casing, and wash and ream the open hole slowly to bottom. This avoids pushing the bit into the BDOslurry and possibly pressuring up the hole causing lost circulation to reoccur. Note: As the BDO pill is circulated to the surface the shale shaker may blind and should be closely watched to prevent mud losses across the screens. BDO pills are not incorporated into the drilling fluid and are not saved for future use! Do not attempt to reverse out unused BDO, as the pipe is likely to become plugged!)
Loe, Chang, and Chevron do not appear to explicitly teach, but Heathman teaches:
further comprising: transporting a fluid loss control treatment design […] wherein the fluid loss control treatment design comprises an inventory of particle types, a carrier fluid, a pumping procedure, or combinations thereof; (Heathman Abstract “The traditional focus of the cementing job of designing adequate slurry properties and getting the slurry properly placed still applies, but that is only the beginning.” Page 3, Right Column, Third Paragraph for its discussion of table 3 “To conclude the analysis, the cement design chosen for this high-stress HTHP application was subjected to a variety of tests. Because of a great variance in the specific gravities of the major components of this blend, concerns emerged regarding the deblending during pneumatic transfer and trucking to location, and about the slurry's mixability. Table 3 shows the results of specific gravity checks pulled from the blend at different times during the handling process, indicating no significant effects. “ The table 3 title indicates there was "300 miles" of "travel"
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to try to move the fluid loss control treatment of Loe according to the teachings of Heathman because a person of ordinary skill in the art would merely have to choose between two options of mixing the slurry on site or transporting the previously mixed slurry.
Regarding claim 11, Loe, Chang, Chevron, Heathman teach the features of claim 10. Loe further teaches:
wherein the inventory of particle types comprise quantities of at least two particle types. (Loe [0039]-[0040] “LCM treatments may include particulate- and/or settable-based treatments. The various material parameters that may be selected may include 1) material type in accordance with considerations based on drilling fluid compatibility, rate of fluid loss, fracture width, and success of prior treatments, etc., 2) the amount of treatment materials, in accordance with the measured or anticipate rate of fluid loss, and 3) particle size and particle size distribution, in accordance with pressure levels, formation type, fracture width, etc. Particulate-based treatments may include use of particles frequently referred to in the art as bridging materials. For example, such bridging materials may include at least one substantially crush resistant particulate solid such that the bridging material props open and bridges or plugs the fractures (cracks and fissures) that are induced in the wall of the wellbore. As used herein, “crush resistant” refers to a bridging material is physically strong enough to withstand the closure stresses exerted on the fracture bridge. Examples of bridging materials suitable for use in the present disclosure include graphite, calcium carbonate (preferably, marble), dolomite (MgCO3.CaCO3), celluloses, micas, proppant materials such as sands or ceramic particles and combinations thereof. Further, it is also envisaged that a portion of the bridging material may comprise drill cuttings having the desired average particle diameter in the range of 25 to 2000 microns.” – There are quantities of at least two particle types.)
Claim 13: Loe, Chang, Hommel, and Jebutu
Claim 13 is rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over US 2009/0188718 A1 to Kaageson-Loe et al. (Loe) in view of NPL: “When Should We Worry About Supercharging in Formation-Pressure-While-Drilling Measurements?” by Chang et al. (Chang) and NPL: “Porosity-Permeability Relations for Evolving Pore Space: A Review with a Focus on (Bio-)geochemically Altered Porous Media” by Hommel et al. (Hommel), and NPL: “Enhanced Formation Integrity Test FIT Interpretation and Decision Making Through Real-Time Downhole Pressure Measurements” by Jebutu et al. (Jebutu).
Regarding claim 13, while Loe, Chang, Hommel, and Janda fail to explicitly teach the following feature, Loe, Chang, and Hommel in view of Jebutu Teaches
further comprising: processing the at least one real-time dataset to generate a periodic dataset. (Jebutu Abstract “Acquiring accurate dcnvnhole pressure data for casing shoe test interpretation and real-time decision making is critical to the delivery of a safe, efficient, and cost-effective well. \.Vith modern logging-while-drilling (L\VD) technology, pressure profiles from a formation integrity test (FIT) or leak-off test (LOT) can now be measured during wellbore pressurization, stored in the memory of the downhole tool, and transmitted in a compressed 60-point pressure versus-time data format via mud-pulse telemetry when circulation is reestablished. This data are decoded and decompressed at the surface to provide a detailed downhole flow-off pressure profile. If a higher-resolution data set is required, a "zoom" function using the same telemetry loop can be affected over a selected (smaller) time interval to provide another 60 (enhanced) pressure points. The ability to transmit these data sets real-time, without a special downlink, saves rig time and ensures quality data as well as test objectives are attained before terminating the test.” Page 5, Last paragraph “For long-duration flow-off events, such as a LOT/FlT, which can take up to an hour or more to complete, the operator should be made aware of, and agree to, the time required to transrnit multiple 60-point uplinks. The time required to transrnit will be dependent on the telemetry rate, the Duration parameter for each 60 points of uplink, and the duration of the LOT/FIT (flow-off event). Table 1 indicates the time needed to send the initial 60-point uplink for an overview of the entire LOTiFIT test ("Overview· of Entire Flow-off Event" column), and the following 60-data point uplink(s), with a resolution of 10 seconds per data point, for different durations of LOT/HT tests. Because the normal range of telemetry rates are from 3 to 20 bits per second, only 0.3 minutes (18s) to l.9 minutes (114s) of telemetry time is required for each uplink of 60-data point flow-off annular pressure profile data.”)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the drill/pressure data collection of Loe by the periodic pressure data processing of Jebutu because the person of ordinary skill in the art would be motivated to improve the data collection of the downhole pressure of Loe using the controlled data collection methods that do not require a special downlink of pressure data that saves rig time and ensures quality data, while achieving all necessary testing objectives. (Loe [0090] “Planning the wellbore may initially include defining drilling data for drilling at least a segment of a planned wellbore. The segment may include, for example, a predetermined length, a specific formation, a time period, and a wellbore depth. Drilling data may include any data that may be used to plan wellbores, such as wellbore lithology, porosity, tectonic activity, fracture gradient, fluid type, fluid properties, hydraulic pressure, fluid composition, well path, rate of penetration, weight on bit, torque, trip speed, bottom hole assembly design, bit type, drilling pipe size, drill collar size, and casing location. Drilling data may include offset well data, experience data collected from similar drilling operations, or data such as that collected during prior remedial treatment operations.” [0028] “Further, the severity of the fluid loss will be related to the cause of the lost circulation, and may be characterized by the pressure within the loss zone and by the rate of fluid loss. The pressure in the loss zone can be estimated based, in part, on the fluid volume added to top-off the well, i.e., the fluid volume required to re-fill the well. Specifically, the pressure within the loss zone may calculated as follows”; Jebutu Abstract “This data are decoded and decompressed at the surface to provide a detailed downhole flow-off pressure profile. If a higher-resolution data set is required, a "zoom" function using the same telemetry loop can be affected over a selected (smaller) time interval to provide another 60 (enhanced) pressure points. The ability to transmit these data sets real-time, without a special downlink, saves rig time and ensures quality data as well as test objectives are attained before terminating the test.”)
Claim 16: Loe, Chang, Hommel, and Li
Claim 16 is rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over US 2009/0188718 A1 to Kaageson-Loe et al. (Loe) in view of NPL: “When Should We Worry About Supercharging in Formation-Pressure-While-Drilling Measurements?” by Chang et al. (Chang) and NPL: “Porosity-Permeability Relations for Evolving Pore Space: A Review with a Focus on (Bio-)geochemically Altered Porous Media” by Hommel et al. (Hommel), and NPL: “Simulation of the interactions between multiple hydraulic fractures and natural fracture network based on Discrete Element Method numerical modeling” by Li (Li).
Regarding claim 16, Loe, Chang, and Hommel appear to fail to explicitly teach, but Loe, Chang, and Homme in view of Li teaches:
wherein the fracture model calculates a fracture as one of a group selected from a natural fracture, an induced fracture, or a highly permeable zone. (Li Page 2927 “According to the observation of shale outcrops, natural joint inclination arrangement has a certain regularity, as shown in Figure 6. Through the field measurement in the Wei-201-HX reservoir, the probability distribution of natural fractures was obtained. Based on the direction and inclination of the seismic source breaking plane, the discrete statistics of natural joints or fracture directions in shale were obtained to get the modeling basis for the DFN model based on statistical results.”)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the determination of properties of the wellbore/formation in Loe by the determinations of the nature of formations in Li because the person of ordinary skill in the art would be motivated to augment the generic determination of the wellbore/formation of Loe with the 91.7% accurate model of Li for determining fractures/formations. (Loe [0041] “The concentration of the bridging material may vary depending, for example, on the type of fluid used, and the wellbore/formation in which the bridging materials are used.”; Li Abstract “Finally, the results by the data from field measurement in Sichuan, China verified that the proposed coupled DFN–DEM model had an accuracy up to 91.7%.The research results provide a reference for predicting the development of fracture network far away for multistage fracturing treatment.”)
Claims 17-18: Loe, Chang, Hommel, Heathman, and Chevron
Claim 17-18 are rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over US 2009/0188718 A1 to Kaageson-Loe et al. (Loe) in view of NPL: “When Should We Worry About Supercharging in Formation-Pressure-While-Drilling Measurements?” by Chang et al. (Chang) and NPL: “Porosity-Permeability Relations for Evolving Pore Space: A Review with a Focus on (Bio-)geochemically Altered Porous Media” by Hommel et al. (Hommel), NPL: “Simulation of the interactions between multiple hydraulic fractures and natural fracture network based on Discrete Element Method numerical modeling” by Heathman et al. (Heathman), and NPL: “Loss Circulation Guide” by Chevron. (Chevron).
Regarding claim 17, Loe, Chang, and Hommel teach the features of claim 12. Loe, Chang, and Hommel appear to fail to explicitly teach, but Loe, Chang, and Hommel in view of Chevron teach
further comprising: transportingcombinations thereof; mixing a fluid loss control treatment, by the pumping equipment, per the pumping procedure; and pumping the fluid loss control treatment per the pumping procedure. (Chevron Pages 32-33 THE BENTONITE-DIESEL OIL (BDO) OR BENTONITE-SYNTHETIC OIL (BSO) SLURRY AND SQUEEZE IN WATER BASED DRILLING FLUIDS “Formula: 1. 300-400 pounds bentonite 2. 1 bbl of diesel oil, mineral oil or synthetic oil (final volume 1.42 bbl) 3. Lost circulation material optional at 10-12 ppb. 4. Barite as needed for density Squeeze Procedure: 1. Locate loss zone and run in hole open ended. Ideally, the loss zone should be known so the BDO can be placed efficiently where needed. If hole conditions allow place the pipe just above the loss zone, if not place the end of the pipe inside the casing. 2. Determine the volume of slurry to pump. Typically, a 40 barrel pill is used. It is advisable to mix in 10 bbl increments as to provide easier cleanup of the pumping equipment. 3. Pump a 5-10 bbl base oil spacer ahead and behind the slurry. 4. Pump pill to bottom of pipe and follow spacer with drilling fluid. 5. Close the blow out preventers. 6. Pump the slurry out the drill string at 1-2 bbl/minute and pump drilling fluid into annulus at 4-8 bbl/min for a thinner initial slurry pump at 8-16 bbl per minute down the annulus. 7. When one half the slurry from drill string is displaced; reduce pump rates to 1 bbl/min on the drill pipe and 1-3 bbl/min on the annulus. 8. When desired pressure is reached, maintain pressure on casing. Displace the drill string volume with drilling fluid and pull into casing. 9. Maintain pressure on the well for approximately 3 hours. 10.Circulate and condition the drilling fluid in the casing, and wash and ream the open hole slowly to bottom. This avoids pushing the bit into the BDOslurry and possibly pressuring up the hole causing lost circulation to reoccur. Note: As the BDO pill is circulated to the surface the shale shaker may blind and should be closely watched to prevent mud losses across the screens. BDO pills are not incorporated into the drilling fluid and are not saved for future use! Do not attempt to reverse out unused BDO, as the pipe is likely to become plugged!” Page 72, Last Paragraph “The slurry was pumped into place with a cement truck pump truck” Page 20 “2. Cement pump truck needed if low volume pump rate required” Page 22 “The unweighted slurry can be mixed in a clean, uncontaminated mud pit and pumped with rig pumps. The operators should consider using a cement company blender and pump truck to place weighted Diaseal M LCM slurries of 12.0 ppg. This gives better control of squeeze pressure and avoids contamination.” Page 39 Disadvantages “Requires two cement pump trucks to mix and place the pill properly)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the high-level descriptions of fluid loss control treatments in Loe by the specific pump procedures and LCM mixtures of Chevron because a person of ordinary skill in the art would be motivated based on the desire to optimize fluid loss control treatments expressed in Loe using the specific blends in Chevron that can bring a dysfunctional/leaking well back to operation with the benefit of 180 years of total experience in the methods. (Loe [0003] “Embodiments disclosed herein relate generally to lost circulation experienced during drilling a wellbore. In particular, embodiments disclosed herein relate to the detection, classification, and remedial treatment of lost circulation occurrences. Additionally, embodiments disclosed herein also relate to the anticipation of lost circulation during wellbore planning and preventative treatments to minimize the occurrences of such lost circulation.” [0029] “Additionally, the severity may also be classified by the rate at which the fluid is being lost. Specifically, loss rates may be classified into general categories of seepage loss (less than 3 m3/hr), partial loss (3-10 m3/hr) where some fluid is returned to the surface, and severe to total loss (greater than 10 m3/hr) where little or no fluid is returned to the surface through the annulus.”; Chevron Page 4, LOSS OF CIRCULATION FOREWARD “In a broad survey conducted by Drilling Specialties Company loss of circulation was identified as the most costly problem faced by the oil and gas industry associated with drilling fluids. The purpose of this CD is to inform the reader of the nature of this problem and ways to solve it. This CD was prepared by a team of individuals that combined have over 180 years’ experience in the drilling fluids business.”)
While Loe, Chang, Hommel, and Chevron fail to teach the following features, Loe, Change, Hommel, and Chevron in view of Heathman teach:
transporting [a] fluid loss control treatment design […] to a well site (Heathman Abstract “The traditional focus of the cementing job of designing adequate slurry properties and getting the slurry properly placed still applies, but that is only the beginning.” Page 3, Right Column, Third Paragraph for its discussion of table 3 “To conclude the analysis, the cement design chosen for this high-stress HTHP application was subjected to a variety of tests. Because of a great variance in the specific gravities of the major components of this blend, concerns emerged regarding the deblending during pneumatic transfer and trucking to location, and about the slurry's mixability. Table 3 shows the results of specific gravity checks pulled from the blend at different times during the handling process, indicating no significant effects. “ The table 3 title indicates there was "300 miles" of "travel")
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to try to move the fluid loss control treatment of Loe according to the teachings of Heathman because a person of ordinary skill in the art would merely have to choose between two options of mixing the slurry on site with mixing/pumping equipment or transporting the previously mixed slurry.
Regarding claim 18, Loe, Chang, Hommel, Chevron, and Heathman teach the features of claim 17 and further teach:
wherein the inventory comprises quantities of at least two particle types. (Chevron Pages 32-33 THE BENTONITE-DIESEL OIL (BDO) OR BENTONITE-SYNTHETIC OIL (BSO) SLURRY AND SQUEEZE IN WATER BASED DRILLING FLUIDS “Formula: 1. 300-400 pounds bentonite 2. 1 bbl of diesel oil, mineral oil or synthetic oil (final volume 1.42 bbl) […] 4. Barite as needed for density )
Claim 20: Loe, Chang, Chevron, Heathman, Jacqueline, and Concrete Rhino
Claim 20 is rejected under pre-AIA 35 U.S.C. 103(a) as being unpatentable over US 2009/0188718 A1 to Kaageson-Loe et al. (Loe) in view of NPL: “When Should We Worry About Supercharging in Formation-Pressure-While-Drilling Measurements?” by Chang et al. (Chang), NPL: “Loss Circulation Guide” by Chevron. (Chevron), NPL: “Jamming and critical outlet size in the discharge of a two-dimensional silo” by Janda et al (Janda), NPL: “Finite Element Analysis Couples Casing and Cement Designs for HP/HT Wells in East Texas” by Heathman et al (Heathman), NPL: “Cementing Technology and Procedures” by Jaqueline et al. (Jacqueline), and NPL “Concrete Rhino” by automation logic (Concrete Rhino).
Regarding claim 20, Loe, Chang, and Chevron, teach:
transporting a well servicing operation comprising a pumping equipment to the new wellsite, (Chevron Page 26, First Paragraph “The use of a blender truck or a tank with agitation is recommended and the following procedure followed.” Page 72, Last Paragraph “The slurry was pumped into place with a cement pump truck” Page 20 “2. Cement pump truck needed if low volume pump rate required” Page 22 “The unweighted slurry can be mixed in a clean, uncontaminated mud pit and pumped with rig pumps. The operators should consider using a cement company blender and pump truck to place weighted Diaseal M LCM slurries of 12.0 ppg. This gives better control of squeeze pressure and avoids contamination.” Page 39 Disadvantages “Requires two cement pump trucks to mix and place the pill properly” – Pump and/or blender trucks are transported to sites. POSITA would have inferred, given the use of trucks in Chevron, that the pump truck and blender truck were transported to the wellsite, or at least found it an obvious variant because trucks are a means of transporting equipment, and when it’s a new wellsite as claimed, POSITA would have found it an obvious variant to transport existing trucks, e.g. from other well-sites or a depot, to the new wellsite.)
(Loe [0056] “Based on the measured rate of fluid loss (ST105) a drilling engineer then categorizes the fluid loss, and reviews a matrix of loss control material blends for the given fluid loss rate. For example, in one embodiment, a drilling engineer may measure the rate of loss (ST105) to be a seepage loss. For a seepage loss (ST106), the options for solving the fluid loss may include pumping one or more loss control blends (in this embodiment, one selected from three choices) downhole.” Chevron Page 37-38 Down Hole Activated Polymer Pills “Mixing a pill in diesel or mineral oil requires two cement-pumping units to mix the pill and move mud on both the drill pipe and annulus or one cement unit to place the pill and the rig pump to mix the mud with the pill down hole.” – POSITA would infer, or at least be suggested, to have multiple blends with different materials from the recitation of one or more loss control blends in Loe paragraph [0056] and/or from Chevron Pages 37-38. Also, MPEP 2144.04(VI)(B) for duplication of parts being prima facie obvious: “Although the reference did not disclose a plurality of ribs, the court held that mere duplication of parts has no patentable significance unless a new and unexpected result is produced.”
receiving(Chevron Page 37, Last Paragraph – Page 38 First Paragraph “These pills are high concentrations of polymer typically 300 to 350 ppb suspended in an inert carrier such as diesel or mineral oil. These polymer plugs form hard very plastic plugs when the pill contacts the mud or formation fluid and some are used to control water flow on producing wells. Mixing a pill in diesel or mineral oil requires two cement-pumping units to mix the pill and move mud on both the drill pipe and annulus or one cement unit to place the pill and the rig pump to mix the mud with the pill down hole. Down hole activated polymer pills can be selected to work in various brines.” Page 38, Fifth-Seventh Paragraph “Pump 3-5 barrels of spacer followed by the pill and another 3-5 barrels of spacer to isolate the polymer pill from the drilling fluid, followed by enough drilling fluid to place the bottom of the pill at the bottom of the pipe. Close the blow out preventers to allow annular injection down the string. The planned pumping program should be determined by the site specific objectives and conditions. These factors can alter the following placement procedure.”)
mixing a fluid loss control treatment(Chevron Page 37, Last Paragraph – Page 38 First Paragraph “These pills are high concentrations of polymer typically 300 to 350 ppb suspended in an inert carrier such as diesel or mineral oil. These polymer plugs form hard very plastic plugs when the pill contacts the mud or formation fluid and some are used to control water flow on producing wells. Mixing a pill in diesel or mineral oil requires two cement-pumping units to mix the pill and move mud on both the drill pipe and annulus or one cement unit to place the pill and the rig pump to mix the mud with the pill down hole. Down hole activated polymer pills can be selected to work in various brines.”)
pumping the fluid loss control treatment per the pumping procedure. (Chevron Page 38, Eighth Paragraph “Commence pumping down the drill string at a maximum rate of 2-3 barrels per minute and down the annulus at a slower rate. The polymer will react very fast with the drilling fluid.”)
Loe, Chang, and Chevron appear to fail to explicitly teach, but Loe, Chang, and Chevron in view of Heathman teach
transporting a fluid loss control treatment comprising an inventory of fluid loss control material to the new wellsite, and wherein the inventory includes at least two supplies of fluid loss control materials (Heathman Abstract “The traditional focus of the cementing job of designing adequate slurry properties and getting the slurry properly placed still applies, but that is only the beginning.” Page 3, Right Column, Third Paragraph for its discussion of table 3 “To conclude the analysis, the cement design chosen for this high-stress HTHP application was subjected to a variety of tests. Because of a great variance in the specific gravities of the major components of this blend, concerns emerged regarding the deblending during pneumatic transfer and trucking to location, and about the slurry's mixability. Table 3 shows the results of specific gravity checks pulled from the blend at different times during the handling process, indicating no significant effects. “ The table 3 title indicates there was "300 miles" of "travel"… Also, see this in view of Loe [0066]-[0067] “Additionally, the recorded data may be used in Subsequent wellbore planning operations, such that when later wellbores are drilling through like formation types, a drilling engineer may predict the types of fluid losses the drilling operation is likely to experience. Thus, the collected data from the selected Solutions and implementations may be used as drilling data in characterizing alternative solutions”)
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to try to move the fluid loss control treatment of Loe according to the teachings of Heathman because a person of ordinary skill in the art would merely have to choose between two options of mixing the slurry on site or transporting the previously mixed slurry.
Loe, Chang, Chevron, and Heathman appear to not explicitly teach, but Loe, Chang, Chevron, and Heathman in view of Jacqueline teach:
connecting the pumping equipment to the wellbore, wherein the pumping equipment is fluidically connected to the wellbore; (Jacqueline Page 32, Plate 9 (shown below) - This illustrate pumping equipment fluidically attached to the wellbore.)
PNG
media_image5.png
683
543
media_image5.png
Greyscale
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the drilling operation including pumps of Loe to include the connection between the pumping unit and the wellbore in Jacqueline because the person of ordinary skill in the art would be motivated to fluidically connect the pump to the wellbore of Loe in accordance with recommended methods and procedures of a textbook from a reputable society in Jacqueline (Loe [0053] “When determining whether fluid loss is a surface loss (ST103), drilling engineers should check all possible surface loss points, such as open valves, defective mud pumps, and cracked fluid line seals. If the floss loss is determined to be the cause of a surface loss, the drilling engineer should stop, locate, and fix (ST104) the cause of the surface loss. After resolving the surface loss, drilling engineer should proceed to drill ahead (ST101).” [0097] “In one embodiment for a continuous particle addition while drilling a short interval, the loss control media may be added directly to the active pit or spotted at the drill bit. While drilling, the shaker screens may be either entirely bypassed, or alternatively, all except the scalping deck of a multiple deck vibratory separator may be removed. Thus, the loss control medial may be directly recycled and retained in the drilling fluid, thereby retaining a maximum amount of the loss control media. However, such a configuration may result in large volumes of cuttings in the active system, and while the cuttings may assist the loss control media, the cuttings may also result in higher fluid rheology, wear on pumps, wear on logging while drilling tools, and risk plugging logging while drilling tools. As such, in certain embodiments, it may be beneficial to predict an affect of the solution on a drilling tool assembly parameter, such as a components of the bottom hole assembly.”; Jacqueline Page 1 Introduction “Cementing is a difficult operation, and the quality of the result depends on many factors associated with: (a) The state of the open hole section. (b) The equipment and materials employed. (c) The fluids used. (d) The procedures applied. Success in cementing depends on the observance of a set of rules, each of which is necessary but not sufficient. It would be futile to try to offset the failure to meet one of them by the ostensibly favorable adaptation of another. It is also important to point out that cementing demands a very precise organization of the job: all the persons involved must be thoroughly familiar with the details of the operation and the role they have to play. This document represents an update of the information and recommendations on methods and procedures to be applied at the well site, and has been prepared as part of the ARTEP "Cements and Cementing" Project.”)
Loe, Chang, Chevron, Heathman, and Jacqueline appear to fail to explicitly teach, but Loe, Chang, Chevron, Heathman, and Jacqueline in view of Concrete Rhino teach:
wherein the pumping equipment includes a unit controller, and wherein the unit controller comprises a processor and memory […] receiving, by the unit controller, a design for the fluid loss control treatment, wherein the design comprises at least one of the supplies of fluid loss control materials and a pumping procedure; […] mixing a fluid loss control treatment, by the unit controller, per the pumping procedure (Concrete Rhino’s Brochure illustrates an image, shown below, in which the particles and fluids are selected and automatically fed for mixing using the controller. Also, the controller is “Touchscreen Tablet Capable (for dirty environments or in-truck operation).”)
PNG
media_image6.png
699
777
media_image6.png
Greyscale
It would have been obvious to a person of ordinary skill in the art before the effective filing date of the claims to modify the generic blending of Loe by the fully automated blending of Concrete Rhino because a person of ordinary skill in the art would be motivated to mix the blends of Loe that are supposed to reduce costs of fluid losses and use the fast, secure, easy to use, error-reducing, customer satisfying, best system for the money, mixing equipment controller of Concrete Rhino. (Loe [0030] “However, partial losses are greater than seepage losses, and thus the cost of the fluid becomes more crucial in the decision to drill ahead or combat the losses. Drilling with partial losses may be considered if the fluid is inexpensive and the pressures are within operating limits. Severe to total losses, on the other hand, typically almost always requires regaining circulation and treatment of the losses.” [0061] “Such a consideration may be applicable if the fluid loss is not enough to constitute a drilling problem, if is not economical to delay drilling, or if the drilling fluid being used is not cost intensive.” [0116] “Advantageously, embodiments of the present disclosure may allow for the remedial treatments of fluid loss during drilling. Particularly, remedial treatment may allow for the classification of drilling loss based on a measurement of the rate of fluid loss, and corresponding solutions for a given classification may be determined. The classification may thereby allow for more accurate solutions to drilling fluid loss to be identified and employed, decreasing costs associated with drilling.”; Concrete Rhino Page 2, Top Customer Review “[…] and am absolutely convinced they are, by far, the best system for the money. I’m putting the Rhino on all my plants.” Bottom Customer Review “As an owner I like how fast the computer system batches concrete and how accurate the system is. I also like how the accounting system integrates with our Great Plains accounting system at our main office. We are very satisfied and pleased with the system.” Seller Assertion Below The Reviews “Why pay twice as much for software that is confusing and hard to use when the Concrete Rhino Automated Batching System will reduce errors and improve your bottom line?”)
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure.
(From Prior Action)
NPL “Flow Rate of Particles through Apertures Obtained from Self-Similar Density and Velocity Profiles” by Janda et al. (Teaches parameters that are useful in determining parameters of the claims)
NPL “An Engineered Approach to Design Biodegradables Solid Particulate Diverters: Jamming and Plugging” by Shahri et al. (Teaches equations for determining jamming)
NPL: “A probability-Based Pore Network Model of Particle Jamming in Porous Media” by Li et al.
US 20130181155 A1 to Robison et al. (Teaches an equation for probability of jamming)
NPL: “Composition and Properties of Drilling and Completion Fluids” by Caenn et al. (Teaches designing for filtration properties of filter cakes)
US 2019/0032476 A1 to Yerubandi et al. (Teaches a simple fluid loss rate equation)
Any inquiry concerning this communication or earlier communications from the examiner should be directed to JAY MICHAEL WHITE whose telephone number is (571)272-7073. The examiner can normally be reached Mon-Fri 11:00-7:00 EST.
Examiner interviews are available via telephone, in-person, and video conferencing using a USPTO supplied web-based collaboration tool. To schedule an interview, applicant is encouraged to use the USPTO Automated Interview Request (AIR) at http://www.uspto.gov/interviewpractice.
If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, Ryan Pitaro can be reached at (571) 272-4071. The fax phone number for the organization where this application or proceeding is assigned is 571-273-8300.
Information regarding the status of published or unpublished applications may be obtained from Patent Center. Unpublished application information in Patent Center is available to registered users. To file and manage patent submissions in Patent Center, visit: https://patentcenter.uspto.gov. Visit https://www.uspto.gov/patents/apply/patent-center for more information about Patent Center and https://www.uspto.gov/patents/docx for information about filing in DOCX format. For additional questions, contact the Electronic Business Center (EBC) at 866-217-9197 (toll-free). If you would like assistance from a USPTO Customer Service Representative, call 800-786-9199 (IN USA OR CANADA) or 571-272-1000.
/J.M.W./Examiner, Art Unit 2188 /RYAN F PITARO/Supervisory Patent Examiner, Art Unit 2188