Abstract: Various embodiments disclosed relate to methods, compositions, and systems for enhanced oil recovery including a viscosifier polymer. In various embodiments, the present invention provides a method of enhanced oil recovery that can include obtaining or providing a composition that includes a viscosifier polymer. The viscosifier polymer includes an ethylene repeating unit including a —C(O)NH2 group and an ethylene repeating unit including an —S(O)2OR1 group, where the repeating units are in block, alternate, or random configuration. At each occurrence R1 can be independently selected from the group consisting of —H and a counterion. The method can include placing the composition in a subterranean formation downhole via an injection wellbore. The method can also include extracting material comprising petroleum from the subterranean formation downhole via a production wellbore.

Abstract: An invert emulsion drilling fluid, and a method of drilling with such fluid, having improved rheology at low mud weights and high temperatures. The improved rheology is effected with addition of a rheology additive of the invention comprising fatty dimer diamines or dimer diamines and an organic acid or ester of the acid. A nonlimiting example of such a rheology additive comprises a C36 fatty dimer diamine and adipic acid or dimethyl adipate.

Abstract: Some embodiments described herein relate to methods comprising providing a proposed invert emulsion formulation, wherein the proposed invert emulsion formulation comprises an oil phase, an aqueous phase, and a particulates fraction comprising a first sub-fraction and a second sub-fraction, wherein the first sub-fraction comprises high-gravity particulates and the second sub-fraction comprises low-gravity particulates; calculating an initial associative stability value of the proposed invert emulsion based on the degree of association between the aqueous phase and the particulates fraction comprising both the first sub-fraction and the second sub-fraction; manipulating the proposed invert emulsion based on the initial associative stability value so as to produce an associatively stable invert emulsion having a final associative stability value in the range of between about 50% and about 100%; and introducing the associatively stable invert emulsion into a subterranean formation.

Abstract: An invert emulsion drilling fluid, and a method of drilling with such fluid, having improved rheology at low mud weights and high temperatures. The improved rheology is effected with addition of a rheology additive of the invention comprising fatty dimer diamines or dimer diamines and an organic acid or ester of the acid. A nonlimiting example of such a rheology additive comprises a C36 fatty dimer diamine and adipic acid or dimethyl adipate.

Abstract: Methods for analyzing sag in a section of a wellbore may utilize computational methods that produce sag profiles, which may be useful in performing further wellbore operations. The computational method may include inputs of at least one wellbore fluid property, at least one wellbore condition relating to a section of a wellbore, at least one operational parameter into a computational method, and any combination thereof. Further, the computational methods may include a mass balance analysis for individual elements of the meshed section of the wellbore.

Abstract: Methods of drilling or treating a well including the steps of: designing a fluid with high-gravity solids (e.g., barite); calculating the sagged fluid mud weight after allowing for sag according to formulas; forming a fluid according to the sagged fluid mud weight; and introducing the fluid into the well. The methods can be used to help control the well or to avoid excessive drilling torque or pressure, kick, or lost circulation due to sag of high-gravity solids such as barite.

Abstract: A method of predictive modeling of a treatment fluid comprises: determining the value of properties of a base fluid and insoluble particulates; providing a proposed suspending agent; performing a first calculation of the suspendability of the proposed suspending agent as determined by a yield gravity function equation; evaluating if the result from the first calculation indicates a stable treatment fluid comprising the base fluid, the insoluble particulates, and the proposed suspending agent, or if the result does not indicate a stable treatment fluid, then: modifying the value of at least one of the properties of the proposed suspending agent, base fluid, and/or insoluble particulate; and performing a second calculation, wherein the same or different property values are continued to be modified and the calculation is continued to be performed until the result indicates a stable treatment fluid; and introducing the stable treatment fluid into a wellbore.

Abstract: A method for enhancing the rheology of drilling fluids that is effective for any mud weight “clay-free” invert emulsion drilling fluid, even when drilling at high temperatures. The improved rheology is effected with addition of a silicon oil to the drilling fluid. A nonlimiting example of such a rheology additive comprises polydimethylsiloxane.

Abstract: An apparatus and method for determining a formation/fluid interaction of a target formation and a target drilling fluid is described herein. The method may include training an artificial neural network using a training data set. The training data set may include a formation characteristic of a source formation and a fluid characteristic of a source drilling fluid and experimental data on source formation/fluid interaction. Once the artificial neural network is trained, a formation characteristic of the target formation and fluid characteristic of target drilling fluid may be input. The formation characteristic of the target formation may correspond to the formation characteristic of the source formation. The fluid characteristic of the target drilling fluid may correspond to the fluid characteristic of the source drilling fluid. A formation/fluid interaction of the target formation and the target drilling fluid may be determined using a value output by the artificial neural network.

Abstract: A method of predictive modeling of a treatment fluid comprises: determining the value of properties of a base fluid and insoluble particulates; providing a proposed suspending agent; performing a first calculation of the suspendability of the proposed suspending agent as determined by a yield gravity function equation; evaluating if the result from the first calculation indicates a stable treatment fluid comprising the base fluid, the insoluble particulates, and the proposed suspending agent, or if the result does not indicate a stable treatment fluid, then: modifying the value of at least one of the properties of the proposed suspending agent, base fluid, and/or insoluble particulate; and performing a second calculation, wherein the same or different property values are continued to be modified and the calculation is continued to be performed until the result indicates a stable treatment fluid; and introducing the stable treatment fluid into a wellbore.

Abstract: A method of servicing a wellbore comprises determining a cation exchange capacity of a sample of a shale, determining a swelling characteristic of the shale using the cation exchange capacity in an equation comprising a term of the form: Az % salt=x(cation exchange capacity)y where Az % salt is a final swelling volume of the shale in the presence of an aqueous fluid having a salt concentration of z %, and x and y are empirical constants, determining a composition of a wellbore servicing fluid based on the determined swelling characteristic, and drilling the wellbore using the wellbore servicing fluid.

Abstract: Methods including providing a wellbore in a subterranean formation having at least one pore opening; providing a proposed wellbore operation; providing a proposed treatment fluid; providing proposed FLCM particulates; calculating the suspendability of the proposed FLCM particulates in the proposed treatment fluid as determined by a yield gravity function based on properties of the proposed treatment fluid and properties of the proposed FLCM particulates or as determined by an experimental FLCM function; manipulating at least one of the properties of the proposed treatment fluid, the properties of the proposed FLCM particulates, or the proposed wellbore operation based on the yield gravity function or the experimental FLCM function so as to produce a FLCM-suspension treatment fluid; and introducing the FLCM-suspension treatment fluid into the wellbore in the subterranean formation so as to contact the at least one pore opening.

Abstract: Methods including providing a wellbore in a subterranean formation having at least one pore opening; providing a proposed wellbore operation; providing a proposed treatment fluid; providing proposed FLCM particulates; calculating the suspendability of the proposed FLCM particulates in the proposed treatment fluid as determined by a yield gravity function based on properties of the proposed treatment fluid and properties of the proposed FLCM particulates or as determined by an experimental FLCM function; manipulating at least one of the properties of the proposed treatment fluid, the properties of the proposed FLCM particulates, or the proposed wellbore operation based on the yield gravity function or the experimental FLCM function so as to produce a FLCM-suspension treatment fluid; and introducing the FLCM-suspension treatment fluid into the wellbore in the subterranean formation so as to contact the at least one pore opening.

Abstract: Methods of drilling or treating a well including the steps of: designing a fluid with high-gravity solids (e.g., barite); calculating the sagged fluid mud weight after allowing for sag according to formulas; forming a fluid according to the sagged fluid mud weight; and introducing the fluid into the well. The methods can be used to help control the well or to avoid excessive drilling torque or pressure, kick, or lost circulation due to sag of high-gravity solids such as barite.

Abstract: A method for enhancing the rheology of drilling fluids that is effective for any mud weight “clay-free” invert emulsion drilling fluid, even when drilling at high temperatures. The improved rheology is effected with addition of a silicon oil to the drilling fluid. A nonlimiting example of such a rheology additive comprises polydimethylsiloxane.

Abstract: An apparatus and method for determining a formation/fluid interaction of a target formation and a target drilling fluid is described herein. The method may include training an artificial neural network using a training data set. The training data set may include a formation characteristic of a source formation and a fluid characteristic of a source drilling fluid and experimental data on source formation/fluid interaction. Once the artificial neural network is trained, a formation characteristic of the target formation and fluid characteristic of target drilling fluid may be input. The formation characteristic of the target formation may correspond to the formation characteristic of the source formation. The fluid characteristic of the target drilling fluid may correspond to the fluid characteristic of the source drilling fluid. A formation/fluid interaction of the target formation and the target drilling fluid may be determined using a value output by the artificial neural network.

Abstract: An invert emulsion drilling fluid, and a method of drilling with such fluid, having improved rheology at low mud weights and high temperatures. The improved rheology is effected with addition of a rheology additive of the invention comprising fatty dimer diamines or dimer diamines and an organic acid or ester of the acid. A nonlimiting example of such a rheology additive comprises a C36 fatty dimer diamine and adipic acid or dimethyl adipate.

Abstract: A method of servicing a wellbore comprises determining a cation exchange capacity of a sample of a shale, determining a swelling characteristic of the shale using the cation exchange capacity in an equation comprising a term of the form: Az% salt=x(cation exchange capacity)y where Az% salt is a final swelling volume of the shale in the presence of an aqueous fluid having a salt concentration of z %, and x and y are empirical constants, determining a composition of a wellbore servicing fluid based on the determined swelling characteristic, and drilling the wellbore using the wellbore servicing fluid.

Abstract: Of the many compositions and methods provided herein, one method includes providing a drilling fluid comprising a base drilling fluid and a plurality of particulates, wherein the base drilling fluid without the particulates is characterized by N1(B) and wherein the base drilling fluid with the particulates is characterized by N1(A); and adjusting a concentration of the particulates in the drilling fluid by comparing the value of ?N1(F) to ?N1(P) so that ?N1(F)??N1(P), wherein ?N1(F)=|N1(A)|?|N1(B)|.

Abstract: A method for determining a Plug Normal Stress Difference (?N1(P)) may include providing a test base drilling fluid that is characterized by N1(TB); adding a first concentration of a test particulate to the test base drilling fluid; adjusting the concentration of the test particulate in the test base drilling fluid to achieve a minimum concentration of the test particulate in the test base drilling fluid that will substantially plug a tapered slot, wherein the test base drilling fluid with the minimum concentration of the test particulate is characterized by N1(TA); and calculating ?N1(P)=|N1(TA)|?|N1(TB)| wherein each First Normal Stress Difference is measured by the same procedure.