(RH) IN AN AUTOCLAVE

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of related U.S. Provisional Application No.

61/379582, filed September 2, 2010, entitled "Method to Asses Environmental Cracking in Sour HPHT Environments from Downhole Phase Analysis of Surface Production or Sampling Data," to Indranil Roy et al., the disclosure of which is incorporated by reference herein in its entirety. This application also claims the benefit of related U.S. Provisional Application No. 61/379516, filed September 2, 2010, entitled "Method to Asses Susceptibility of Downhole Alloys to Cracking in Sour HPHT Dense Gas," to Indranil Roy et al., the disclosure of which is incorporated by reference herein in its entirety.

BACKGROUND OF INVENTION

[0002] The hydrogen sulfide (H ₂ S) content of fluids in oil wells has an important impact on the production operations of the well. Wells having drilling conditions with significant hydrogen sulfide presence may generally be categorized as having a "sour" drilling environment. Sour drilling environments are considered corrosive, and thus require particular selection of corrosion resistant drilling equipment. Further, increased temperatures and pressures may increase the level of corrosive conditions.

[0003] The National Association of Corrosion Engineers ("NACE") has issued guidelines to test and determine how severe the possibility of sulfide stress corrosion cracking is in a material. NACE defines sulfide stress corrosion cracking as the cracking of metal involving corrosion and stress (residual and applied) in the presence of hydrogen sulfide and water. Generally, NACE guidelines require testing metals in aqueous environments containing hydrogen sulfide, and may be conducted in ambient or elevated temperatures and pressures. In addition to hydrogen sulfide, the test gas usually includes a mixture of C0 ₂ and/or inert gas, such as N ₂ or Ar. At low hydrogen sulfide partial pressures, tests in inert gas without C0 ₂ require careful interpretation because of corrosion product solubility effects. To determine the partial pressure of hydrogen sulfide, NACE suggests an appended method. Particularly, the test vessel shall be heated with valves closed to test temperature and stabilized, and the system pressure (the vapor pressure of the test solution), PI, shall be measured. The test gas shall be admitted to the vessel until the test pressure, PT, is reached. The hydrogen sulfide partial pressure, pH ₂ S, in the test environment is given approximately in Equation (1),

pH ₂ S = (PT - Pl) X _H2S (1)

where X _H2S is the mole fraction of hydrogen sulfide in the test gas.

[0004] Tests conducted in sour brine may include, for example, tensile tests, bent- beam tests, C-ring tests and double-cantilever-beam tests. Metal samples are tested to determine if the metal meets a certain minimum level of environmental cracking resistance. Environmental cracking resistance ratings may be based on, for example, the highest no-failure stress in a certain time period, the statistically based critical stress factor for a 50% probability of failure in a certain time period, and the average threshold stress intensity factor for sulfide stress corrosion cracking for valid tests of replicate test specimens.

[0005] In addition to NACE methods, there are also commercial models available for predicting environmental cracking of downhole alloys. However, the available commercial models are typically limited to relatively benign environments (not in high pressure and high temperature environments). Further, dense sour gases are commonly rationalized as a media with low dielectric constant, unable to solvate halides in their dielectric continuum or screen ions, thereby being non reactive to exposed metallurgy. Thus, prior art methods of testing metals for susceptibility to environmental cracking have been limited to testing in sour fluids.

SUMMARY OF INVENTION

[0006] In one aspect, embodiments disclosed herein relate to a

method of determining susceptibility of an alloy to environmental cracking in a wellbore environment including exposing the alloy to high pressure high temperature sour dense gas with specified relative humidity in a test apparatus; measuring the amount of environmental cracking resulting in the alloy; and tuning a thermodynamic model based on the measured environmental cracking of the alloy.

[0007] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

[0008] FIG. 1 shows a drawing of a well system used in downhole phase analysis according to embodiments of the present disclosure.

[0009] FIG. 2 shows a diagram of well system phase analysis according to embodiments of the present disclosure. [0010] FIG. 3 shows a diagram of a method according to embodiments of the present disclosure for selecting a downhole alloy based on results of a thermodynamic model of a well system.

[0011] FIG. 4 shows a graph of results from a thermodynamic model according to embodiments of the present disclosure.

[0012] FIG. 5 shows a drawing of a test apparatus used to simulate a well system in embodiments of the present disclosure.

[0013] FIG. 6 shows a picture of an autoclave according to embodiments of the present disclosure.

[0014] FIG. 7 shows an autoclave test vessel according to embodiments of the present disclosure.

[0015] FIG. 8 shows a phase diagram of well conditions determined by a thermodynamic model according to embodiments of the present disclosure.

[0016] FIG. 9 shows a phase diagram of well conditions determined by a thermodynamic model according to embodiments of the present disclosure.

[0017] FIG. 10 shows a diagram of a method according to embodiments of the present disclosure for determination of susceptibility of downhole alloys to environmental cracking in sour HPHT dense gas with specific relative humidity.

[0018] FIG. 11 shows a diagram of a method according to embodiments of the present disclosure of determining susceptibility of an alloy to environmental cracking in a wellbore environment. DETAILED DESCRIPTION

[0019] The following description concerns a number of embodiments and is meant to provide an understanding of the embodiments. The description is not in any way meant to limit the scope of any present or subsequent related claims.

[0020] As used herein, the terms "above" and "below"; "up" and "down"; "upper" and "lower"; "upwardly" and "downwardly"; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or diagonal relationship as appropriate.

[0021] The rising demand for energy and our depleting natural oil and gas reserves has prompted exploration for hydrocarbons at greater depths and hostile environments. However, substantial technology gaps remain in bringing ultra- HPHT sour fields (e.g., 20,000 psi and 400 °F and beyond) on-stream. The presence of sour gases coupled with high pressure and high temperature (HPHT) poses significant engineering challenges to operators and service providers alike. To harness these reservoirs, a comprehensive understanding of the downhole chemistry is helpful. Proper design and selection of apposite metallurgy may help prevent potentially disastrous consequences such as loss of well control land related environmental catastrophe stemming from material failure.

[0022] Contrary to conventional thought that dense sour gases are non-reactive to exposed metallurgy, severe environmental cracking of 80 ksi (hardness < 22 HRC) low alloy steel ("LAS") stressed "C" rings in simulated sour ultra HPHT reservoir conditions (425 °F and 20,000 psi) is observed. Attempts have previously been made to understand this phenomenon through thermodynamic modeling of equilibrated downhole phases, but cogent explanations for the occurrence of environmental cracking in these hostile conditions were not conclusive. Further, as discussed above, prior art methods for testing susceptibility of downhole alloys to environmental cracking has been limited to testing in sour brine (fluids). According to conventional thought, corrosion would not occur in dense gases with less than 100% relative humidity until dew point temperature was reached, when condensed water drops out of the gas phase.

[0023] However, the inventors of the present disclosure have discovered that corrosion may occur in dense gases with less than 100% relative humidity until dew point temperature is reached, when condensed water drops out of the gas phase. In particular, the inventors of the present disclosure have found a tendency of dense sour gases with high relative humidity at ultra-HPHT reservoir conditions to solvate halides, screen ions, exhibit ionic activity, and cause environmental cracking.

[0024] In view of the present discovery that corrosion may occur in dense gases with less than 100% relative humidity until dew point temperature is reached when condensed water drops out of the gas phase, the inventors of the present disclosure have found prior art testing solutions to be insufficient for determining alloy susceptibility to environmental cracking in HPHT sour dense gas reservoirs with a specific relative humidity. Problems with NACE testing may include, for example, the capability of testing labs to deliver the gas mixture to HPHT conditions if it contains hydrogen sulfide to be delivered to an autoclave at HPHT conditions; capability of testing labs to deliver the gas mixture to HPHT conditions if the pressure is beyond the supercritical conditions (pressure and temperature) of one of the gas components; calculation of hydrogen sulfide partial pressure if the test conditions include acid gases in supercritical states; and the effect of solubility of water in the supercritical acid gases and ionic constituents present in the aqueous and dense phase.

[0025] Methods according to embodiments of the present disclosure relate to a workflow that establishes a method to predict susceptibility of downhole alloys to environmental cracking in HPHT sour gas condensate reservoirs. For example, methods according to some embodiments of the present disclosure relate to assessing environmental cracking in HPHT sour environments from downhole phase analysis of surface production or sampling data. Other methods described herein relate to tests of susceptibility of downhole alloys to environmental cracking after exposure to HPHT sour dense gases with specified relative humidity in an autoclave. The results of the methods described herein may help successfully harness, develop, complete and safely produce ultra HPHT sour gas-condensate brine reservoirs.

[0026] As used herein, "high temperature effect" is defined as deviation(s) from ideal behavior of a reservoir, reservoir fluid, or a phase of a reservoir fluid, at elevated temperatures, such as greater than 300°F, 350°F, 400°F, 450°F, 500°F or greater in various embodiments. As used herein, "pressure effect" is defined as the influence pressure may have on the behavior of a reservoir, reservoir fluid, or phase of a reservoir fluid. As used herein, "high pressure effect" is defined as deviation(s) from ideal behavior of a reservoir, reservoir fluid, or a phase of a reservoir fluid, at elevated pressures, such as greater than 15 ksi, 20 ksi, 25 ksi, 30 ksi or greater in various embodiments. Models or algorithms used to estimate or predict the character of a reservoir, reservoir fluid, or phase of a reservoir fluid in embodiments disclosed herein thus include functions or derivations to more accurately calculate or estimate one or more properties of the reservoir, reservoir fluid, or phase of a reservoir fluid accounting for one or more of these effects.

[0027] Reservoir fluids are known to those of ordinary skill in the art to contain various phases and components. For example, reservoirs may include an aqueous phase (e.g., water and dissolved salts), a hydrocarbon gas phase (e.g., hydrogen, methane, ethane, ethylene, and other light hydrocarbons, as well as carbon dioxide, hydrogen sulfide, and numerous other compounds), and a liquid hydrocarbon phase (e.g., pentanes, hexanes, etc., which may include heavy hydrocarbons, such as asphaltenes), as well as carbon dioxide, hydrogen sulfide, among numerous other compounds. Thermodynamic models used in embodiments herein may rely on a database of stored properties for one or more of these components, which may include one or more of molecular formula, molar weight, as well as pressure-volume-temperature data (such as one or more of phase envelopes, boiling points, melting points, density, viscosity, solubility, etc.).

[0028] Thermodynamic models have now been developed that account for the high temperature effects on properties of the brine, including the non-ideal behavior discovered at extreme downhole conditions. Functions, algorithms, or derivations used to account for the high temperature effects on the brine that may be included in embodiments of the thermodynamic model may account for changes in one or more of molecular interactions, solubility constants or solubility characteristics of water (solvating power), density, electronegativity, dipole moment, heat capacity, hydrogen bonding, miscibility, as well as electrophoretic/relaxation effects and ion pairings, among others, as a function of temperature, including deviations from ideal behavior that may be estimated, measured, or observed at elevated downhole temperatures. [0029] Embodiments of the thermodynamic model may also account for the effect of pressure on the brine, and thus on the geological formation and the character of the reservoir fluid. Heretofore the effect of pressure on conductivity / resistivity or various other properties of a downhole fluid has not been accounted for in efforts to determine the character of a reservoir. Thermodynamic models according to embodiments disclosed herein may include functions or derivations to account for the effect of pressure on the brine. Such functions or derivations, in some embodiments, may also account for deviations from ideal behavior at elevated pressures (the high pressure effect). Functions, algorithms, or derivations used to account for the pressure effects and high pressure effects on the brine that may be included in embodiments of the thermodynamic model may account for changes in one or more of molecular interactions, solubility constants or solubility characteristics of water (solvating power), density, electronegativity, dipole moment, heat capacity, hydrogen bonding, miscibility, as well as electrophoretic/relaxation effects and ion pairings, among other properties of the brine, as a function of temperature, including deviations from ideal behavior that may be estimated, measured, or observed at elevated downhole pressures.

[0030] For example, the pressure effect on solubility of a salt in water may be represented by the following equation:

δ Ρ RT

where the index i iterates the components, N; is the mole fraction of the i component in the solution, P is the pressure, the index T refers to constant temperature, Vi _>aq is the partial molar volume of the 1 ^th component in the solution, Vi _>cr is the partial molar volume of the 1 ^th component in the dissolving solid, and R is the universal gas constant. [0031] It has also been surprisingly found that hydrocarbon gases, particularly the dense gas phase, especially at high temperature and high pressure, may solvate ions and exhibit conductivity. In previous models, the resistivity of the dense gas phase was assumed infinite (no conductivity). However, at relatively high temperatures and/or pressures, the dense gas phase may indeed contribute to the conductivity of the formation fluid, and thus need to be accounted for to properly characterize a reservoir and the fluids contained therein.

[0032] Thermodynamic models have now been developed that account for the high temperature effects on properties of the dense gas phase, including the non-ideal behavior discovered at extreme downhole conditions. Functions, algorithms, or derivations used to account for the high temperature effects on the dense gas phase that may be included in embodiments of the thermodynamic model may account for changes in one or more of molecular interactions, solubility constants or solubility characteristics of water (solvating power), density, electronegativity, dipole moment, heat capacity, hydrogen bonding, miscibility, as well as electrophoretic/relaxation effects and ion pairings, among others, as a function of temperature, including deviations from ideal behavior that may be estimated, measured, or observed at elevated downhole temperatures.

[0033] Embodiments of the thermodynamic model may also account for the effect of pressure on the dense gas phase, and thus on the geological formation and the character of the reservoir fluid. Heretofore the effect of pressure on conductivity / resistivity or various other properties of a downhole fluid has not been accounted for in efforts to determine the character of a reservoir. Thermodynamic models according to embodiments disclosed herein may include functions or derivations to account for the effect of pressure on the dense gas phase. Such functions or derivations, in some embodiments, may also account for deviations from ideal behavior at elevated pressures (the high pressure effect). Functions, algorithms, or derivations used to account for the pressure effects and high pressure effects on the dense gas phase that may be included in embodiments of the thermodynamic model may account for changes in one or more of molecular interactions, solubility constants or solubility characteristics of water (solvating power), density, electronegativity, dipole moment, heat capacity, hydrogen bonding, miscibility, as well as electrophoretic/relaxation effects and ion pairings, among other properties of the dense gas phase, as a function of temperature, including deviations from ideal behavior that may be estimated, measured, or observed at elevated downhole pressures.

34] With respect to ion pairing and other effects that may be accounted for in the model, embodiments of the model used to determine or estimate the character of a reservoir may also include functionalities relative to numerous dissolved salts or ions. Heretofore, conductivity / resistivity algorithms were based on sodium chloride dissolved in the aqueous phase. However, brines and dense gases found in reservoirs around the world may contain other ions or mixtures of ions, such as sodium-, magnesium-, calcium- , potassium-, and strontium- chlorides, bromides, borates, bicarbonates, and sulfates, among other salts that may be present in underground reservoirs as may be known to those of ordinary skill in the art. Embodiments of the model used to characterize a reservoir may thus account for differences in conductivity / resistivity that may occur based on the ions present in the brine, based on ions present in the dense gas as well as the high temperature effects, pressure effects, and/or high pressure effects on the ions and the brine and the dense gas. [0035] Archie's equation, shown below, relates resistivity of a geological formation to its porosity and brine saturation and is typically used to estimate hydrocarbon saturation of the geological formation.

1/Rt = <D ² /a [Sw ² R _w ] (Archie's equation)

where R _T is the total resistivity in the formation, Φ is the porosity of the formation, S _w is the water saturation of the formation and R _W is the water resistivity. Heretofore, the conductivity of a fluid-saturated rock was presumed to be primarily a function of the brine content of the reservoir fluid. Archie's equation treats formation and hydrocarbon resistivities as infinite; however, at relatively high temperatures and/or pressures, the dense gas phase may indeed contribute to the conductivity of the formation fluid, and thus needs to be accounted for to properly characterize a reservoir and the fluids contained therein.

[0036] Embodiments of the model used to characterize a reservoir may thus account for the effect of conductivity in the dense gas phase, based on a modified Archie's equation as shown below in Equations 1 or 2.

1 Rt = 0 ² /a [S _W ² /R _W + S _G ² /R _G ] Equation 1 or 1/R _T = <D ² /a [S _W ² /R _W + (1-S _W ) ² /R _G ] Equation 2

where So is the dense gas phase saturation and RQ is the resistivity of the dense gas phase.

[0037] In embodiments, at least one property of the brine may be derived from the stored data and one or more empirical relationships may be derived from an analysis of the pressure- volume-temperature data. In embodiments, at least one property of the dense gas phase may be derived from the stored data and one or more empirical relationships may be derived from an analysis of the pressure-volume-temperature data. Empirical relations are derived from an analysis of the stored properties for the compounds and/or groups of compounds (e.g., regression analyses or other numerical methods). For derivation of the empirical relation, it is generally preferred to use transforms having smooth and continuous first and second derivatives for algorithmic estimation of properties. Accordingly, the high temperature effect and/or high pressure effect may be accounted for in the model by use of one, two, three, or more transforms encompassing the overall temperature ranges and/or pressure ranges experienced during drilling and production of reservoirs. In some embodiments, for example, the high temperature effect may be accounted for based on an additive function (i.e., property = f(temperature) + f(high temperature effect)). In other embodiments or for other empirical relations, the high temperature effect may be accounted for by delineation of the algorithm over discrete temperature intervals (i.e., if x<T<y, property = f(T), if y<T<z, property = f'(T), etc.). In yet other embodiments, various "constants" used for calculating properties of compounds or interactions between compounds or groups of compounds, such as binary interaction parameters, may be input as a function of temperature or may be input as a constant having different values for discrete temperature ranges. Similar considerations may be used for the pressure effect and high pressure effect.

38] In addition to the empirical relations derivable from the stored data, the property(ies) and empirical relationships can be used to generate an Equation of State model for predicting one or more properties of the reservoir, the reservoir fluid, or a phase of the reservoir fluid, where the equation of state model may incorporate, may be tuned, or may be modified to incorporate the bound water, the high temperature, pressure, and/or high pressure effects as recognizable or derived in the empirical relations. As used herein, an Equation of State model capturing the high temperature effect includes one or more equations to calculate chemical and/or physical properties of a system. The equations of the Equation of State model may include the above-derived empirical relationships, may be equations based on the above-derived empirical relationships, and may also include various equations from various Equations of State known to those of skill in the art. Examples of Equations of State which may be used, tuned, and/or modified may include the Sen-Goode-Sibbit EOS, the Redlich-Kwong EOS, the Soave- Redlich-Kwong EOS, Peng Robinson EOS, and others known to one of ordinary skill in the art. The properties of the brine, dense gas phase, and bound water that may be predicted using an Equation of State model may include conductivity, resistivity, density, viscosity, compressibility, composition (e.g., dissolved hydrocarbon content, salinity / ion concentration, ion / salt type(s), etc.), phase activity, pH, free energy, heat capacity, entropy, enthalpy, chemical potentials, and diffusion coefficients, among others.

39] Thus, embodiments disclosed herein include a method for generating a model to characterize a wellbore, where the model incorporates at least one of a temperature effect, a pressure effect, and a high pressure effect. Characterization of the wellbore using thermodynamic modeling, as described above, may be used to test the susceptibility of a downhole alloy to environmental cracking in a high pressure high temperature (HPHT) sour dense gas. According to some embodiments, a method for selecting downhole alloys for use in a well system may include measuring at least one property of the well system, inputting the at leas tone property into a thermodynamic model, simulating the well system using the thermodynamic model, and selecting a downhole alloy for the use in the well system based on at least one result of the simulation. For example, a method to assess environmental cracking in HPHT sour environments may include a downhole phase analysis of surface production or sampling data, which may then be input into a thermodynamic model for simulation of the wellbore downhole environment. Referring to FIG. 1, a drawing of a well system used in downhole phase analysis according to embodiments of the present disclosure is shown. As shown, a wellbore 100 is drilled to a HPHT reservoir 110. A phase analysis may be performed for the environment of the HPHT reservoir 110, the wellbore 100, and at the surface 120 of the wellbore. At the surface 120, a separator 130 may be used to separate water 140 from the remaining gases.

[0040] According to an example of a downhole phase analysis performed in accordance with embodiments of the present disclosure, a phase analysis of a well system with an HPHT reservoir producing ionized dense fluids and sour brine may demonstrate a varying ratio of H ₂ S, C0 ₂ , Ci, and H ₂ 0 through the well system. For example, the phase analysis results may show a gas ratio at the HPHT reservoir including 13% H ₂ S, 16% C0 ₂ , 34% Ci, and 37% H ₂ 0 (saturated); a gas ratio at a dew point in the wellbore including 25% H ₂ S, 24% C0 ₂ , and 51% Ci (H ₂ 0 precipitates out from gases at the dew point); and a gas ratio from the separator including 25% H ₂ S, 24% C0 ₂ , and 51% C _\ . Phase analysis may be performed for other well systems that produce gas ratios of various compositions. Further, downhole phase analysis of a well system may be conducted based on surface production or sample data (described more below).

[0041] Referring now to FIG. 2, a diagram of well system phase analysis according to embodiments of the present disclosure is shown. As shown, at least one property of the well system may be determined based on the phase composition at the well surface (surface phase analysis) and/or the phase composition at a downhole point in the well system (downhole phase analysis). For example, surface phase analysis may be performed from samples taken at a separator, and downhole phase analysis may be performed from downhole samples taken by, for example, a Modular Formation Dynamics Tester ("MDT") or Drill Stem Test ("DST") for points in the wellbore or in the reservoir. The gas ratios determined from phase analysis at the well surface may correlate with the gas ratios determined from phase analysis of the downhole phases. Thus, thermodynamic modeling according to embodiments of the present disclosure may be used to predict gas ratios of well system phases based, in part, on such correlation. In an example well system phase analysis, both surface and downhole production compositions may include H ₂ S, C0 ₂ , C - C _n , and H ₂ 0, wherein the gas ratio of the surface production correlates with the gas ratio of the downhole production.

42] The correlation between surface phase analysis and downhole phase analysis may be used with thermodynamic modeling to more accurately predict and simulate wellbore environments. The results of wellbore simulation using the thermodynamic modeling described herein may be used to select an alloy for use downhole in the wellbore. Referring now to FIG. 3, FIG. 3 shows a diagram of a method according to embodiments of the present disclosure for selecting a downhole alloy based on results of a thermodynamic model of a well system. As shown, at least one property of a geological formation, such as salinity, temperature, pressure, ion types, and phases, are input into a thermodynamic model according to embodiments of the present disclosure. Inputs to the model may include, for example, Reservoir Conditions (temperature and pressure), phases, overall compositional data (such as from sample bombs depressured and analyzed or measured or estimated using downhole tools), ion / salt types, number of phases, phase ratios, and porosity, among others. For example, phases may include at least one of dense gas (e.g., H ₂ S, C0 ₂ , and Ci-C _n ), brine, and condensate (e.g., Ci-C _n and trace amounts of other components). The overall compositional data may include, for example, hydrocarbon content, hydrocarbon (Ci to C _n ) number and concentration data, overall salinity, water content, and gas (C0 ₂ , H ₂ S, etc.) content, among others.

43] Further, various temperature and pressure conditions may be input into the thermodynamic model to simulate a well system. For example, bottom hole conditions may have conventional temperature and pressure conditions (temperatures of less than or equal to 300 °F and pressures of less than or equal to 10 ksi), HPHT temperature and pressure conditions (temperatures of greater than 300 °F and less than or equal to 350 °F and pressures of greater than 10 ksi and less than or equal to 15 ksi), ultra-HPHT temperature and pressure conditions (temperatures of greater than 350 °F and less than or equal to 400 °F and pressures of greater than 15 ksi and less than or equal to 20 ksi), and extreme HPHT temperature and pressure conditions (temperatures of greater than or equal to 400 °F and pressures of greater than or equal to 20 ksi). The thermodynamic model of embodiments of the present disclosure (described above) may be used to predict the well system phase compositions and interaction parameters including, for example, aqueous phase activity, dense phase fugacity, pH, conductivity, viscosity, dew and bubble points, density, chemical potentials, and diffusion co-efficients. Further, one or more results of the thermodynamic model may be used to calculate the partial pressure of hydrogen sulfide at a pressure and temperature of the well system, which may then be used to select the downhole alloy(s) used in the well system. As shown in FIG. 3, when the bottom hole partial pressure of hydrogen sulfide is less than 600 psi, NACE guidelines may be applied for downhole alloy selection (materials that are resistant to environmental cracking in the calculated downhole environment). However, when the bottom hole partial pressure of hydrogen sulfide is greater than or equal to 600 psi, the general guidelines for non-NACE material selection may be applied in order to select a downhole alloy that is resistant to environmental cracking in the calculated bottom hole environment.

[0044] Referring now to FIG. 4, a graph of results from a thermodynamic model according to embodiments of the present disclosure is shown. Measurements of mole percentages of hydrogen sulfide (e.g. , 1% H ₂ S, 2% H ₂ S, 5% H ₂ S, and 10% H ₂ S) taken from a separator may be plotted in a graph correlating bottom hole mole percentage of hydrogen sulfide in relation to bottom hole temperature (BHT), with the bottom hole pressure (BHP) equal to 10 ksi. As shown, the bottom hole reservoir conditions may be predicted and the bottom hole partial pressure of hydrogen sulfide may be calculated based on the results of the thermodynamic model. For example, shown at example point 1, if a 5% H ₂ S mole percentage is measured at a well separator, the partial pressure of hydrogen sulfide at a well bottom hole may be calculated to be 425 psi when the BHT is 375 °F and the BHP is 10 ksi (P _H2S = (4.25% H ₂ S mole percentage at bottom hole) x (10 ksi BHP)). In another example, referring to the plot in FIG. 4 of the 1% H ₂ S mole percentage measured at a separator, the bottom hole partial pressure of hydrogen sulfide may be calculated to be about 100 psi when the BHT is 250 °F and the BHP is 10 ksi (P _ff i>s = (~1% H ₂ S mole percentage at bottom hole) x (10 ksi BHP)).

[0045] By using thermodynamic modeling of the present disclosure, vapor-liquid equilibrium and liquid-liquid equilibrium phase compositions and interaction parameters (e.g. , aqueous phase activity, dense phase fugacity, pH, conductivity, viscosity, dew and bubble points, etc.) may be predicted for well systems, including HPHT well systems, using inputs from surface production, downhole testing data, MDT or DST sampling data. Using the phase analysis and interaction parameters determined from the thermodynamic modeling, susceptibility of downhole metallurgy to environmental cracking in hostile HPHT sour environments may be accurately predicted.

[0046] According to other embodiments of the present disclosure, thermodynamic modeling may also be used in conjunction with material testing in a test apparatus, such as an autoclave, to determine susceptibility of an alloy to environmental cracking in sour HPHT dense gas. In some embodiments, methods of modeling a well system environment includes measuring at least one property of the well system, inputting at least one property into a thermodynamic model, and calculating a loading recipe from at least one result of the thermodynamic model to determine test conditions in a test apparatus In additional embodiments, methods of determining susceptibility of an alloy to environmental cracking in a wellbore environment include exposing the alloy to high pressure high temperature sour dense gas with specified relative humidity in a test apparatus, measuring the amount of environmental cracking resulting in the alloy, and tuning a thermodynamic model based on the measured environmental cracking of the alloy.

[0047] A drawing of a test apparatus used to simulate a well system environment in embodiments of the present disclosure is shown in FIG. 5. As shown, alloy samples in the form of stressed C rings 505 are positioned in an autoclave 500. A dip tube 510 may be inserted into the autoclave 500 for gas and liquid loading, and a release tube 515 may be inserted into the autoclave for gas passage to valves and a scrubber (not shown). Further, the autoclave 500 test conditions may include a dense phase extending a distance x inches of the autoclave 500 and a sour brine phase extending a distance y inches of the autoclave 500. FIG. 6 shows a picture of an example autoclave 600 and stressed C ring samples 605 according to embodiments of the present disclosure. Depending on the test conditions selected, gas and liquid loading may result in a dense phase and a brine phase. According to other embodiments, test conditions for an autoclave may be selected to have a dense phase extending the entire length of the autoclave (the sour brine phase extends 0 inches), wherein the dense phase may have a specified relative humidity.

[0048] FIG. 7 shows another example of an autoclave test vessel 700 according to embodiments of the present disclosure. As shown, an alloy sample in the form of stressed C rings 705 may be contacted with a test solution 720 in the autoclave 700. A gas mixture may be inserted into the autoclave 700 using a regulator 730, and gas may be released through a condenser 740 and measured with a pressure gauge 745.

[0049] The testing conditions in a test apparatus of embodiments disclosed herein may be determined by thermodynamic modeling. According to embodiments, a loading recipe may be calculated with the thermodynamic model and testing conditions may be set for exposing the determined loading recipe in a test apparatus. The thermodynamic model may predict, for example, one or more of aqueous phase activity, dense phase fugacity, pH, conductivity, viscosity, dew and bubble points, density, chemical potentials, and diffusion co-efficients. Further, once an alloy has been tested in a test apparatus with testing conditions determined from thermodynamic modeling, the results of the autoclave simulation may be input in the thermodynamic model to increase the accuracy of the thermodynamic model.

[0050] Referring now to FIGS. 8 and 9, phase diagrams of well conditions determined by a thermodynamic model according to embodiments of the present disclosure are shown. As shown in FIG. 8, the amount of water (in mole ) and the amount of water with C0 ₂ and CH ₄ (in mole ) present in a well system is simulated with a thermodynamic model, wherein the well system has a pressure of 20,000 psi, a temperature of 500 °F, and a gas mixture including C0 ₂ (56 mole) and CH ₄ (14 mole). As shown in FIG. 9, the density for the amount of an aqueous water phase and the amount of a second liquid (aqueous phase of C0 ₂ and CH ₄ ) present in a well system is simulated with a thermodynamic model. The results of thermodynamic modeling shown in FIGS. 8 and 9 are examples of results that may be used to accurately predict a well's environment. According to some embodiments, these results may be used to help determine testing conditions in a test apparatus.

[0051] Further, according to embodiments of the present disclosure, a loading recipe may be calculated from results of thermodynamic modeling to form the dense phase and/or sour brine phase testing conditions in a HPHT test apparatus. The loading recipe may include different materials, such as one or more of C0 ₂ , CH ₄ , H ₂ 0, H ₂ S, and NaCl, for example, and in various quantities.

[0052] An example of a loading recipe according to embodiments of the present disclosure is shown below, in Table 1.

Loading Recipe in an HPHT Autoclave

CASE 1 - Autoclave volume 2.7 liters

[0053] As shown, the mole percentages of each element for the loading recipe change according to the different temperature and pressures of the well system (e.g. , at 500 °F and 20 ksi and 120 °F and 300 psi). Upon testing one or more alloy samples in an HPHT autoclave using the determined loading recipe, susceptibility of the alloy samples to environmental cracking in sour HPHT dense gas with specific relative humidity may be measured.

[0054] According to some embodiments of the present disclosure, measurements of environmental cracking in alloy samples tested in a test apparatus may be used to modify the thermodynamic model that determined test conditions for the test apparatus. For example, referring to FIG. 11, a diagram of a method according to embodiments of the present disclosure of determining susceptibility of an alloy to environmental cracking in a wellbore environment is shown. As shown, a thermodynamic model may be used to determine autoclave test conditions that simulate a wellbore environment. A downhole alloy may then be tested in the autoclave (with the calculated test conditions) to determine susceptibility to environmental cracking in the simulated wellbore environment. Results of the autoclave test may then be used to modify or tune the thermodynamic model that was used to determine the autoclave test conditions. A subsequent set of autoclave test conditions may then be calculated based on the tuned thermodynamic model, and a subsequent testing of one or more alloy samples may be performed in the autoclave using the modified test conditions. The cycle of testing shown in FIG. 11 may be repeated one or more times to improve accuracy of the thermodynamic model.

[0055] A diagram is shown in FIG. 10 of another method according to embodiments of the present disclosure for determination of susceptibility of downhole alloys to environmental cracking in sour HPHT dense gas with specific relative humidity. The method shown in FIG. 10 includes the following assumptions: all phases can be conductive (dense gases are conductive); all halides are included; and hydrocarbons at HPHT with dissolved second phases can have some conductivity. As shown, inputs such as salinity, temperature, ion types, pressure, and phases (e.g., Ci-C _n , H ₂ S, C0 ₂ , H ₂ 0, etc) are chosen to input into a thermodynamic model of the present disclosure. The results of the thermodynamic model may be used to determine various features, such as aqueous phase activity, gaseous phase fugacity, density, viscosity, pH, free energy, heat capacity, entropy, enthalpy, phase compositions, chemical potentials, diffusion co-efficients, and the loading recipe. Upon determining a loading recipe, the loading recipe for a dense gas at a specified relative humidity and/or a sour aqueous phase may be used to form the test conditions in a test apparatus, as described above. Depending on the temperature, pressure, and relative humidity conditions of the well system being simulated, NACE or non-NACE guidelines may be used to select downhole alloys that are resistant to environmental cracking in the specified well conditions (sour HPHT dense gas with specific relative humidity).

[0056] Examples: The following testing parameters are provided below to demonstrate prior art testing deficiencies.

[0057] According to one example, an isochoric system (constant volume) autoclave is provided to create the testing environment, wherein the vapor pressure at 425 °F is approximately equal to 300 psi. Pure H ₂ S is injected in the autoclave until the pressure reaches 2,000 psi. According to the equation provided by NACE to determine hydrogen sulfide partial pressure, pH ₂ S, in the test environment - pH ₂ S = (PT - PI) XH ₂ S, where PT is the test pressure, PI is the system pressure (the vapor pressure of the test solution), and XH ₂ S is the mole fraction of H ₂ S in the test gas - the partial pressure of the H ₂ S gas is equal to 1,700 psi. At low pressure (according to tests that have been done traditionally), the above results are approximate. However, at ultra-HPHT, the results are not valid. In particular, there is dissolution of H ₂ S in the aqueous phase as well as dissolution of water in the "dense" H ₂ S.

[0058] However, according to some embodiments disclosed herein, thermodynamic modeling may be used to predict the phase compositions of H ₂ S and water vapor. For example, using thermodynamic modeling of the model parameters given above, the partial pressure of the H ₂ S gas is approximately 1500 psi (pH ₂ S = X _H2S (~ 0.75) x 2,000 psi). Changing the model parameters given above to reach a system pressure of 20,000 psi (instead of 2,000 psi), sufficient amounts of H ₂ S may be present to form a two phase system. Using thermodynamic modeling methods of the present disclosure, it has been observed for such a system that the dense phase formed may have about 22% H ₂ S (the rest is water vapor). Increasing H ₂ S increases the mole % of H ₂ S in the dense phase. Finally, the dense phase collapses and forms a condensed H ₂ S phase where all the water dissolves.

[0059] According to another example, an alloy may be tested with traditional methods at 425 °F and 5,000 psi total system pressure (low pressure conditions) using 100% H ₂ S vapor, wherein the partial pressure of H ₂ S is 3,750 psi. However, if the test parameters were changed to be in high pressure conditions, the traditional methods may result in inaccurate calculations. Using methods according to embodiments of the present disclosure, the alloy may be tested in high pressure conditions, for example at a total system pressure of 20,000 psi, wherein the partial pressure of H ₂ S would equal about 8,000 psi.

[0060] Advantageously, inventors of the present disclosure have found that contrary to conventional thought that liquid must be present to cause environmental cracking, environmental cracking may also occur in dense sour gas (with relative humidity being less than the dew point). In view of this discovery, the present inventors have created a model for determining susceptibility of alloys to environmental cracking after exposure to HPHT sour dense gases with specified relative humidity.

[0061] Particularly, thermodynamic simulations of the present disclosure may predict interaction parameters in HPHT dense gas with specified relative humidity in order to assess susceptibility of downhole alloys to environmental cracking upon exposure to HPHT sour environments. For example, thermodynamic modeling of the present disclosure may be used to predict vapor-liquid equilibrium / liquid-liquid equilibrium phase compositions and interaction parameters, and relative humidity of gas. Additionally, thermodynamic modeling may predict dense phase fugacity, pH, DC conductivity, viscosity, dew and bubble points, to access and model corrosion/environmental cracking of exposed materials and alloys. Advantageously, using methods disclosed herein may provide a more accurate metallurgical prediction for the life cycle of a well (e.g. , Wireline, D&M, Subsea, DST, completions, etc.) in extreme sour service at HPHT environment. Thermodynamic models of the present disclosure may also provide more accurate prediction of relative humidity of dense gases. Methods of the present disclosure may also provide accurate prediction models for steam-assisted gravity drainage ("SAGD") and high temperature wells when compared with prior art methods that do not even extrapolate to such high temperatures.

[0062] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.