ExxonMobil Upstream Research Company v Shell Internationale Research Maatschappij B.V
[2015] APO 54
•19 August 2015
IP AUSTRALIA
AUSTRALIAN PATENT OFFICE
ExxonMobil Upstream Research Company v Shell Internationale Research Maatschappij B.V. [2015] APO 54
Patent Application: 2010258099
Title:Process and apparatus for sweetening and liquefying a gas stream
Patent Applicant: Shell Internationale Research Maatschappij B.V.
Opponent: ExxonMobil Upstream Research Company
Delegate: O L Haggar
Decision Date: 19 August 2015
Hearing Date: 27 May 2015 in Canberra
Catchwords: PATENTS – opposition to the grant of a patent – whether to rely on new information under regulation 5.23 – novelty – whether a broad range anticipates a narrower range – whether the prior art inherently discloses a feature of the claimed invention – inventive step – whether the person skilled in the relevant art is a team – manner of manufacture – whether the claimed invention is directed to a mere scheme or plan – opposition unsuccessful on all grounds – costs awarded against the opponent
Representation: Patent applicant: Ben Fitzpatrick of counsel instructed by Dr Mary Turonek of FB Rice
Opponent:Watermark
IP AUSTRALIA
AUSTRALIAN PATENT OFFICE
Patent Application: 2010258099
Title:Process and apparatus for sweetening and liquefying a gas stream
Patent Applicant: Shell Internationale Research Maatschappij B.V.
Date of Decision: 19 August 2015
DECISION
I dismiss the opposition and award costs according to Schedule 8 of the Patents Regulations against ExxonMobil Upstream Research Company. Subject to any appeal of this decision, I direct that the application proceed to grant.
REASONS FOR DECISION
Background
Patent application 2010258099 was filed by Shell Internationale Research Maatschappij B.V. (Shell) on 11 June 2010 under the provisions of the Patent Cooperation Treaty as international application PCT/AU 2010/000722 with a claimed priority date of 12 June 2009. The application was advertised as accepted on 17 January 2013.
The opposition
Preliminary matters
ExxonMobil Upstream Research Company (Exxon) filed a notice of opposition to the application on 17 April 2013 and a statement of grounds and particulars on 17 July 2013. The evidence in support was completed on 10 October 2013 after the grant of several extensions of time. On 9 October 2013 Shell filed a request to amend the complete specification by replacing the claims as accepted with a new set of claims. It concurrently filed a request for the Commissioner to stay the opposition proceedings. In ExxonMobil Upstream Research Company v Shell Internationale Research Maatschappij B.V. [2014 APO 22 at [27], the Deputy Commissioner of Patents formally directed that the opposition be stayed until the Commissioner advised the parties that the proposed amendment had been allowed, refused or withdrawn.
Leave to amend the specification was advertised on 13 March 2014. The proposed amendment was advertised as allowed on 12 June 2014 following which the stay of the opposition was lifted. The normal evidentiary stages of the opposition were completed on 26 August 2014. In the meantime, on 16 July 2014 Exxon advised that it may seek to formally address the amended claims by filing evidence that was not strictly evidence in reply. After a number of exchanges with the parties, on 21 August 2014 a delegate directed that Exxon had one month in which to file new evidence. The delegate had earlier advised that if new evidence was filed, the Commissioner would decide whether to rely on any of that evidence under regulation 5.23. As it happens, no evidence was filed by Exxon in response to the direction.
The hearing
The opposition was heard in Canberra on 27 May 2015. Shell was represented by Ben Fitzpatrick of counsel instructed by Dr Mary Turonek of FB Rice. Exxon did not appear at the hearing and instead relied on submissions in reply.
Grounds of opposition
The grounds of opposition pressed by Exxon are that:
- the claimed invention is not novel;
- the claimed invention does not involve an inventive step; and
- the claimed invention is not a manner of manufacture.
The evidence
The parties have filed the following evidence:
Evidence in support consisting of declarations by:
- Costa Tsesmelis dated 11 October 2013 (Tsesmelis 1) with Annexures CMT-1 to CMT-8, CMT-9A, CMT-9B, and CMT-10 to CMT-20;
- P Scott Northrop dated 11 October 2013 (Northrop 1) with Annexures PSN-1 to PSN-17, PSN-18A, PSN-18B, and PSN-19; and
- P Scott Northrop dated 15 November 2013 (Northrop 2) with Annexures PSN-20 and PSN-21.
Evidence in answer consisting of a declaration by Craig Dugan dated 26 June 2014 (Dugan) with Annexures A and B, and Exhibits CD-1 to CD-3.
Evidence in reply consisting of declarations by:
- Costa Tsesmelis dated 22 August 2014 (Tsesmelis 2) with Annexures CMT-21 to CMT-26; and
- P Scott Northrop dated 21 August 2014 (Northrop 3) with Annexures PSN-20 to PSN-23.
I will refer to the relevant parts of the evidence where appropriate, but note that in view of the history of the opposition the evidence in support is directed to the claims as accepted, and not to the subsequently amended claims. This much is acknowledged in Northrop 3 at [14.2].
Regulation 5.23 considerations
During the course of the hearing Mr Fitzpatrick took me to information appearing in Chapter 21 of a publication titled the Engineering Data Book, 12th edition, 2004 (the GPA document). This document was exhibited (as RDD-9) in a parallel opposition between the parties concerning application 2008213739, but does not form part of the evidence in the present proceedings. The issue which therefore arises is whether I should rely upon the new information contained in the GPA document under regulation 5.23. The operation of regulation 5.23 was recently considered by a delegate of the Commissioner in Merial Limited v BayerIntellectual Property GmbH [2015] APO 16. After posing the question of how significant does new information need to be before invoking regulation 5.23, the delegate concluded at [25]:
“If the new information is not likely to change the outcome of the opposition in a significant way, there is little advantage gained by bringing it into the opposition … In other words, the new information needs to be significantly better than what is already in evidence.”
The GPA document sets out a number of gas sweetening processes that may be employed to remove acidic components (primarily carbon dioxide and hydrogen sulphide) and other impurities from hydrocarbon streams. However, the same processes are extensively discussed in the evidence already to hand. There is therefore no reason for me to believe that reliance on the GPA document pursuant to regulation 5.23 would be likely to change the outcome of the opposition in a significant way and, accordingly, I will have no further regard to it.
10. Furthermore, although annexed to Northrop 3, PSN-21 and PSN-22 are not referred to in Exxon’s submissions or the statement of grounds and particulars. Nevertheless, on their face these documents appear particularly relevant to the question of inventive step, and I therefore consider it appropriate to rely on them under regulation 5.23.
The specification
11. The specification indicates that the invention generally relates to a process and apparatus for sweetening and liquefying a gas stream, and more particularly for removing sour species in a liquefied form from the gas stream as the sweetened gas stream is progressively cooled to liquefaction temperatures.
12. The specification describes the background to the invention as follows:
“The increasing demand for the usage of light hydrogen gas, such as methane, as a primary energy source is driving the development of natural gas fields that had previously been considered sub-economic, including those containing significant concentrations of carbon dioxide. Additionally, hydrocarbon gas is increasingly being sourced from coal bed and coal seam mining operations, associated gas stream sources, and anthropogenic sources such as landfill gas and biogas.
Although hydrocarbon gas combustion produces significantly lower carbon dioxide emissions than oil or coal, for sources containing high concentrations of carbon dioxide the advantage is lessened or even negated if the carbon dioxide removed in pre-combustion gas processing plants is vented to the atmosphere instead of being captured and stored, for example in sub-surface geological formation.
Additionally, the presence of water or other compounds such as hydrogen sulphide, mercaptans, and mercury which are also referred to as “sour” species or contaminants found in hydrocarbon gas, regardless of the sources listed above, is also problematic. Water and sour contaminants promote corrosion and form solids under conditions commonly found in process operations and distribution networks.”
13. The specification explains that it is necessary to reduce concentrations of water and sour species down to acceptable levels and, accordingly, in the processes currently employed to liquefy hydrocarbon gas, a feed gas is initially pre-treated to deplete carbon dioxide to about 50-200 ppm and remove other sour species. The pre-treatment process is typically a chemical solvent process, but may also be a physical solvent or a hybrid membrane/solvent process. The pre-treated gas is then dehydrated, typically with molecular sieves, before feeding it to a liquefaction plant where the dehydrated sweetened gas is cooled to temperatures typically of about -160oC at which light hydrocarbons, in particular methane, condense.
14. The specification indicates that for feed gases with relatively high carbon dioxide content, the capital and energy expenditure to remove carbon dioxide to about 50-200 ppm by means of the aforementioned conventional techniques is expensive and requires significant utility infrastructure, thereby increasing the environmental footprint of the liquefaction plant.
15. The specification then refers to the process described in US 5,956,971 for producing pressurised liquefied natural gas (PLNG) in which the natural gas feed stream contains a freezable component. Although typically carbon dioxide, hydrogen sulphide or another acid gas, the freezable component can be any compound that has the potential to form solids at cryogenic temperatures required to condense methane. In this process, a separation system containing a controlled freezing zone produces a vapour stream rich in methane and a liquid stream rich in the freezable component. The vapour stream is then cooled to a temperature above about -112oC at a pressure sufficient to produce a pressurised liquefied natural gas stream. Under the warmer operating conditions of this process it is possible to provide PLNG with carbon dioxide levels as high as about 1.4mol % carbon dioxide at temperatures of -112oC and about 4.2% at -95oC without causing freezing problems in the liquefaction process.
16. The specification states that there is a continuing need for an improved process for liquefying natural gas that contains sour species in concentrations that would freeze during the liquefaction process which can be integrated with conventional operating conditions of existing natural gas liquefaction plants, and which reduces the concentration of sour species such as carbon dioxide to less than 50 ppm.
17. The specification then says that the present invention seeks to “overcome at least some of the aforementioned disadvantages”.
18. The specification ends with 28 claims. The independent claims are in the following terms:
“1. A process for liquefying a gas stream comprising hydrocarbons and sour species, the process comprising the steps of:
a) cooling the gas stream by heat exchange with a first refrigerant stream to a temperature marginally greater than at which solidification of the sour species occurs;
b) further cooling the gas stream to a first temperature between about -80oC to -95oC at a pressure between about 15 to 25 bar by expanding the gas stream as it is introduced into a vessel to produce a mixture of solid and/or liquid sour species and a cooled gas stream comprising gaseous hydrocarbons and residual sour species;
c) separating the solid and/or liquid sour species from the cooled gas stream in the vessel;
d) contacting the cooled gas stream with a solvent under temperature conditions close to or at the first temperature to deplete the cooled gas stream of residual sour species, thereby producing a cooled sweetened gas stream; and
e) cooling the cooled sweetened gas stream to a second temperature below the methane boiling point by heat exchange with a second refrigerant stream to produce liquid hydrocarbons.
19. A gas liquefaction apparatus for liquefying a gas stream comprising hydrocarbons and sour species, the gas liquefaction apparatus comprising:
a first cooling zone comprising one or more heat exchangers for cooling the gas stream to a temperature marginally greater than that at which the sour species solidifies and a vessel for further cooling the gas stream to a first temperature between about -80oC to -95oC at a pressure between about 15 to 25 bar by expanding the gas stream as it is introduced into the vessel to produce a mixture of solid and/or liquid sour species and a cooled gas stream comprising gaseous hydrocarbons and residual sour species, the first cooling zone being in fluid communication with a source of gas comprising hydrocarbons and sour species;
the vessel being configured to separate solids and/or liquids from the cooled gas stream in the mixture;
a solvation zone arranged, in use, to contact the cooled gas stream with a solvent under temperature conditions close to or at the first temperature to deplete the cooled gas stream of residual sour species, thereby producing a cooled sweetened gas stream; and
a second cooling zone in fluid communication with the vessel, the second cooling zone comprising a heat exchanger configured to receive and cool the cooled sweetened gas stream to a second temperature between -140oC to -150oC to produce liquid hydrocarbons.
24. A process for recovering liquid carbon dioxide from a gas stream comprising hydrocarbons and carbon dioxide during liquefaction, the process comprising the steps of:
a) cooling the gas stream by heat exchange with a first refrigerant stream to a temperature marginally greater than at which solidification of carbon dioxide [occurs];
b) further cooling the gas stream to a first temperature between about -80oC to -95oC at a pressure between about 15 to 25 bar by expanding the gas stream as it is introduced into a vessel to produce a mixture of solid and/or liquid carbon dioxide and gaseous hydrocarbons and residual carbon dioxide;
c) separating the solid and/or liquid carbon dioxide from the mixture in the vessel, thereby producing a cooled gas stream comprising gaseous hydrocarbons and residual carbon dioxide;
d) heating the separated solid carbon dioxide and producing liquid carbon dioxide;
e) contacting the cooled gas stream with a solvent under temperature conditions close to or at the first temperature to deplete the cooled gas stream of residual carbon dioxide, thereby producing a cooled sweetened gas stream; and
f) cooling the cooled sweetened gas stream to a second temperature below the methane boiling point by heat exchange with a second refrigerant system to produce liquefied hydrocarbons.
19. The invention is said to be based on the realisation that it is possible to recover liquid carbon dioxide from a gas stream comprising hydrocarbons and sour species during a gas liquefaction process in a form suitable to store and/or sequester. This is further stated to facilitate a relative reduction in greenhouse gas emissions in comparison to known processes in which carbon dioxide is removed from the gas stream prior to liquefaction and vented to the atmosphere. The latter attribute is reflected in the following claims:
“25. A method of creating a financial instrument tradable under a greenhouse gas Emissions Trading Scheme (ETS), the method comprising the step of exploiting a process for liquefying a gas stream defined by any one of claims 1 to 18.
26. A method of creating a financial instrument tradable under a greenhouse gas Emissions Trading Scheme (ETS), the method comprising the step of exploiting a gas liquefaction apparatus defined by any one of claims 19 to 23.
27. A method of creating a financial instrument tradable under a greenhouse gas Emissions Trading Scheme (ETS), the method comprising the step of exploiting a process for recovering carbon dioxide from a gas stream comprising hydrocarbons and carbon dioxide during liquefaction defined by claim 24.”
20. Claim 28 stipulates that the financial instrument referred to in the above claims is comprised of one of either a carbon credit, carbon offset or renewable energy certificate.
Onus of proof
21. Examination of the application was requested on 15 September 2011. As a result, substantive amendments of the Patents Act brought about by the Intellectual Property Laws Amendment(Raising the Bar) Act 2012 do not apply. This includes the amendment to subsection 60(3A) that allows the Commissioner to refuse an application if satisfied on the balance of probabilities that a ground of opposition exits.
22. Consequently, the former standard for opposition proceedings applies and Exxon must establish that it is clear or practically certain that a valid patent cannot be granted (F Hoffman La RocheAG v New England Biolabs Inc [2000] FCA 283; 50 IPR 305 at 311, 319; Commissioner of Patents vSherman [2008] FCAFC 182 at [18], [22]; 79 IPR 46; Genetics Institute Inc v Kirin-Amgen Inc [1999] FCA 742; [1999] 92 FCR 106 at [17]).
23. The parties have acknowledged that this standard of proof applies to the present proceedings.
Novelty
24. A claimed invention is deprived of novelty if it has been given to the public before the priority date, either by prior use of a product or process, or by publication of information that equates to the claimed invention (Danisco A/S v Novozymes A/S (No 2) [2011] FCA 282; 91 IPR 209 at [248]). It is well settled that the general test for anticipation or want of novelty is the reverse infringement test (Meyers Taylor Pty Ltd v Vicarr Industries Ltd ([1977] HCA 19; 137 CLR 228 at [19]), and this test is satisfied if the alleged anticipation discloses all of the essential features of the invention as claimed (Nicaro Holdings Pty Ltd v Martin Engineering Co ([1990] FCA 40; 16 IPR 545 at [19]).
25. To meet this requirement, the prior art must contain “clear and unmistakable directions” to produce the invention as claimed (Pfizer Overseas Pharmaceuticals v Eli Lilley and Company [2005] FCAFC 224; 68 IPR 1 at [314]). However, if the prior publication contains a direction which is capable of being carried out in a manner which would infringe the claimed invention, but would at least as likely be carried out in such a way that would not do so, the invention as claimed will not be anticipated (General Tire & Rubber Co v Firestone Tyre & Rubber Co Ltd [1972] RPC 457 at 485-486; 1A IPR 121 at 138, Novozymes A/S v Danisco A/S [2013] FCAFC 6; 99 IPR 417 at [177]).
26. Exxon contends that the claimed invention is anticipated by AU 2006291954 (D1).
27. Before considering the disclosure of D1, it should be explained at this point that natural gas consists of a mixture of hydrocarbon gases composed mainly of methane together with amounts of other hydrocarbons including what are generally referred to as C3+ hydrocarbons or natural gas liquids (NGLs). Natural gas typically also contains varying amounts of what have been alternatively referred to in the evidence as contaminants, acid gases or sour species, especially water, carbon dioxide and hydrogen sulphide, which must be removed from the natural gas before it is either distributed by pipeline for consumption as a saleable product (otherwise known as “sales gas”), or fed to a downstream gas liquefaction plant.
28. D1 discloses a process and apparatus for the removal of sour species, specifically carbon dioxide, in a liquid phase from a dehydrated natural gas stream. The disclosure of D1 is best understood by reference to the embodiment illustrated in Figure 1 which is reproduced below.
29. In this embodiment natural gas from a well head or storage reservoir is subjected to a dehydration process examples of which typically include the use of molecular sieves or solvents. The dehydrated natural gas stream is fed through conduit 14 via a heat exchanger 16 to a flash vessel 18 operating at pressure and temperature conditions in the order of 30 to 70 bar and about -15oC to -40oC. A condensate of C3+ hydrocarbons and a fraction(s) of the sour species is separated from the dehydrated natural gas stream in flash vessel 18 and discharged through conduit 20 for subsequent treatment. In some embodiments, further cooling of the gas stream can be performed downstream of heat exchanger 16 and upstream of flash vessel 18 in a first refrigerated heat exchanger 70a.
30. The dehydrated natural gas stream is then directed through conduit 22 to heat exchanger 24 where it is cooled to a temperature marginally greater than a temperature at which the sour species contained in the dehydrated natural gas stream solidify. The gas stream can be additionally cooled in a second refrigerated heat exchanger 70b.
31. The cooled dehydrated natural gas stream is fed to the solids formation zone 80 of vessel 12 via inlet 28. The cooled gas stream is expanded using a Joule-Thomson valve 26 or other suitable means to further cool the gas stream. The process of expansion cools the dehydrated natural gas stream entering the solids formation zone 80 at inlet 28 to about -70oC to -160oC in a pressure range of 15 to 30 bar. The solid sour species and small amount of hydrocarbon liquids formed under these temperature and pressure conditions form a slurry which is separated from the dehydrated gas stream. The slurry is then heated to a temperature at least marginally greater than the solidification temperature of the solid sour species to convert them to a liquid phase in the lower portion 30 of vessel 12. The liquid stream rich in the sour species is removed from vessel 12 through conduit 34.
32. While most of the sour species in the dehydrated natural gas stream are solidified in the solids formation zone 80 of vessel 12, a fraction of the sour species remains in the gas phase. The dehydrated natural gas stream containing gaseous sour species is directed into the gas solvation zone 90 of vessel 12. A cooled liquid solvent is introduced into the gas solvation zone 90 through inlet 42 which solvates the gaseous sour species. The resulting liquid solution of the gaseous sour species collects in portion 50 of the gas solvation zone 90 for removal via conduit 52 from where it is subjected to a stripping process in fractionation column 56. The stripped solvent is pumped via conduit 62 to heat exchanger 54 for cooling, and then to heat exchanger 48 for further cooling before reintroduction into the gas salvation zone 90.
33. A product stream comprising dehydrated sweetened natural gas is removed from the gas solvation zone 90 through conduit 45. The product gas stream is at a pressure of between 15 to 30 bar and a temperature of -70oC to -100oC. It has a carbon dioxide concentration of 200 ppm.
34. Exxon submits that D1 accordingly discloses each of the process steps set forth in claim1, except for the final step of cooling the sweetened product gas stream to a temperature below the methane boiling point to produce liquid hydrocarbons. However, Exxon further submits that it is implicit from D1 that the product gas stream is intended for cooling to liquefaction temperatures to produce LNG, and that as a result the totality of the disclosure of D1 anticipates the invention defined by claim 1. This further submission is the subject of considerable debate between the parties, and I will have more to say on it later.
35. The position for which Exxon contends rests in the first instance on the footing that D1 explicitly discloses all but the final process step of claim 1. At [106] of its submissions Exxon asserts that:
“There is no dispute between the experts that D1 discloses at least the claimed first and second treatment steps, namely, cooling the gas stream to a temperature where CO2 and other sour contaminants freeze and hydrocarbons such as propane and heavier hydrocarbons would condense to a liquid; and a treatment step with a liquid solvent which absorbs residual sour species.”
36. This assertion overstates the evidence Mr Dugan has provided on behalf of Shell. Mr Dugan acknowledges that D1 discloses a process for removing acid gases, such as carbon dioxide and hydrogen sulphide, from dehydrated natural gas. At Dugan [5.6] he then broadly categorises this process as:
“a two-stage process … in which the dehydrated natural gas feed is first cooled by expanding through a gas expander defining an inlet in a solidification zone of a cooling vessel. Expansion of the feed stream cools the gas to below the sour species solidification temperature and the sour species separate from the gas as solids. The sweetened gas stream is then contacted with a liquid solvent in a gas salvation zone to remove residual sour species still remaining in the sweetened gas stream.”
37. This general appraisal confirms that, in common with the invention defined by claim 1, D1 discloses a process for sweetening a natural gas feed stream in two stages, namely, solidification and solvation. However, and contrary to Exxon’s apparent reading of his evidence, Mr Dugan does not go so far as suggesting that the information conveyed by D1 regarding the manner in which these stages are effected can be directly correlated with the requirements of claim 1. In fact what becomes evident on close analysis is that D1 differs from the invention defined by claim 1 in a number of respects.
38. First, it will be recalled that, in accordance with step (a) of claim 1, the gas feed stream is cooled by heat exchange with a first refrigerant stream to a temperature marginally greater than at which solidification of the sour species occurs. On the other hand, the provision of the first refrigerated heat exchanger 70a is stated in D1 to be entirely optional and, in any event, it is not until the gas feed stream reaches heat exchanger 24 located downstream of the first refrigerated heat exchanger that it is cooled to a temperature marginally greater than at which the sour species solidify. Exxon’s submission at [100] that cooling the feed gas stream to this temperature is achieved in D1 by heat exchange with a first refrigerant stream is therefore misguided.
39. The next difference arises when D1 is compared to step (b) of claim 1. In both cases the gas feed stream is further cooled by expanding the gas stream as it enters a vessel to produce a mixture of solid and/or liquid sour species and a cooled gas stream which includes residual sour species. As already mentioned, vessel 12 in D1 operates under temperature and pressure conditions of -70oC to -160oC, and 15 to 30 bar. The second step of claim 1 recites almost identical pressure conditions, but confines the temperature of the cooled gas stream to about -80oC to -95oC. Exxon submits that it is sufficient for the purposes of anticipation that the temperature range disclosed by D1 encompasses the temperature range recited by claim 1. This is incorrect. As pointed out by Shell, the disclosure of a parameter of broad range in a prior art document does not anticipate a claim to a narrower range of the same parameter unless the narrower range is enabled. Put another way, the prior art document must contain clear and unmistakable directions to select the narrower range from the broad range disclosed. This draws on the principle of practical equality advocated in Hill v Evans [1862] EngR 365. D1 does not provide such an enabling disclosure.
40. This brings me to the final step defined by claim 1 wherein the cooled gas stream, which has by now been depleted of sour species (ie. sweetened), is cooled to a temperature below the methane boiling point by heat exchange with a second refrigerant stream to produce liquid hydrocarbons. Exxon has submitted that this step is implicitly disclosed by D1. At [94], for example, it argues that:
“… a treated natural gas containing a noteworthy low 200 ppm CO2 is very plainly intended for liquefaction by cooling it below the boiling point of methane … There is no other reasonable use for such a natural gas which meets the stringent economical requirements of a natural gas project … The D1 natural gas must be intended for liquefaction.”
41. At [35] of its reply submissions Exxon presses the view that as the process disclosed by D1 produces a treated natural gas stream having a carbon dioxide concentration “much purer than required for sales gas”, the treated gas is plainly intended for liquefaction.
42. I have already found that D1 does not disclose steps (a) and (b) of claim 1, and so the question of whether it implicitly discloses step (e) is a moot point. Nevertheless, I will briefly address this issue given the prominence assigned to it by Exxon.
43. The notion of implicit disclosure was considered in AstraZeneca AB v Apotex Pty Ltd [2014] FCAFC 99; 312 ALR 1 where it was said at [349]:
“ … Whether or not s skilled worker might deduce the desirability of adding such a feature, it cannot be said that any of the [prior disclosures], or anything said in them, infers that the device to which they relate involved the presence of this feature. The appellant argued that the alleged invention makes no ‘difference in substance from that which was known’, presumably by virtue of these [prior disclosures]. But this way of putting the matter, which departs from an investigation as to whether the essential integers of the combination were revealed, risks a coalescence between considerations of novelty and obviousness so as to create an amorphous test on which the modern law of patents has turned its back.”
44. Shell submits that this decision verifies that want of novelty cannot be made out by implication, and to do so impermissibly conflates the grounds of novelty and inventive step.
45. What is made clear by D1 from the outset is that the aim of the process it discloses is to enhance the removal of sour species from a dehydrated natural gas feed stream. D1 is accordingly squarely focussed on the way in which the enhanced process is performed, and in this context effectively looks upon any further treatment of the sweetened gas stream produced by this process as inconsequential. In this respect D1 goes no further than indicating that the sweetened product gas stream can, following further cooling, be used in one or both of heat exchangers 48 and 24 to respectively cool the liquid solvent and the dehydrated natural gas feed stream. Alternatively, the product gas stream may be prepared for use as sales gas, but not before undergoing recompression. The uncontested evidence of Mr Dugan at [8.38] is that in “undergoing a recompression process in preparation for sale, the temperature of the sweetened gas will also inherently rise”. D1 does not in either case infer any motive for cooling the sweetened gas stream to a temperature below the methane boiling point, and thus it cannot be said that the treated gas resulting from the process disclosed by D1 would inevitably be recognised as intended for liquefaction as alleged by Exxon.
46. It also bears comment that step (e) is performed by heat exchange with a second refrigerant stream. The second refrigerated heat exchanger 70b disclosed by D1 is plainly not for this purpose.
47. I therefore do not consider that step (e) of claim 1 is implicitly disclosed by D1, and it seems to me that in arguing to the contrary Exxon has relied on the “amorphous test” rejected by the Full Court in AstraZeneca. The statement at Northrop 3 [12.2] that “it would be very obvious to integrate the process of D1 with a cascaded refrigeration system to cool the gas … to generate LNG” is most telling in this regard.
48. Exxon has not established that D1 deprives claim 1 of novelty. The distinguishing features of claim 1 are in effect shared by independent claims 19 and 24, and consequently all dependent claims, which are therefore likewise novel over D1.
49. This ground of opposition accordingly does not succeed.
Inventive step
50. According to subsections 7(2) and 7(3) as they were before the commencement of the Intellectual Property Laws Amendment (Raising the Bar) Act 2012, the invention is in the present case taken to involve an inventive step, when compared to the prior art base, unless the invention would have been obvious to the person skilled in the relevant art in the light of common general knowledge within Australia either considered alone or together with the information specified in subsection (3). This information includes one or a combination of two or more pieces of prior art information being information that the person skilled in the art could be reasonably expected to have ascertained, understood and regarded as relevant by the person skilled in the relevant art.
51. The test for whether an invention is obvious (non-inventive) is to ask whether it would have been a matter of routine to proceed to the claimed invention. In Wellcome Foundation Ltd v V.R. Laboratories (Aust) Pty Ltd [1981] HCA 12 at [45]; 148 CLR 262 at 286, it was stated:
“The test is whether the hypothetical addressee faced with the same problem would have taken as matter of routine whatever steps might have led from the prior at to the invention, whether they be the steps of the inventor or not.”
52. The High Court approved this approach in Aktiebolaget Hassle v Alphapharm Pty Ltd [2002] HCA 59; 212 CLR 411.
The person skilled in the art
53. The question of whether a claimed invention involves an inventive step is to be determined through the eyes of the person skilled in the art.
54. In KD Kanopy Australasia Pty Ltd v InstaImage Pty Ltd [2007] FCA 41 at [16], the person skilled in the art was said to be:
“a person acquainted with the surrounding circumstances of the state of the art and manufacture at the relevant time … They are likely to have a ‘practical interest in the subject matter of the invention’ … and may often work in the art with which the invention is connected … Some may be more skilled in the relevant art than others.”
55. In the present case the problem addressed by the specification is to improve the process of removing sour species from natural gas. It is broadly agreed between the parties that the person skilled in the art is a chemical engineer having knowledge of hydrocarbon gas processing. However, Exxon goes one step further in submitting that in view of the “extraordinarily broad” nature of this field it is necessary to have regard to the knowledge held by a team of chemical engineers.
56. Shell has rejected the team approach postulated by Exxon. It reasons that as stated in Minnesota Mining and Manufacturing Co v Tyco Electronics Pty Ltd [2002] FCAFC 315; 56 IPR 248 at [91], the team approach applies only where the solution to a problem requires the joint efforts of experts from different arts, and requires evidence of how knowledge could be shared through interaction between or amongst the experts. As pointed out by Shell, Exxon “has drawn on the expertise of two chemical engineers – it does not draw on the expertise of any expert outside of the field”. It consequently submits that Exxon has misused the concept of a team in attempting to cumulatively assimilate the knowledge of experts from the same field.
57. Having considered the matter I do not believe that in the present circumstances anything turns on whether the person skilled in the art is taken to be an individual or a composite entity. As concluded by the delegate in ExxonMobil Upstream Research Company v ShellInternationale Research Maatschappij BV [2015] APO 39 at [60] after considering the very same issue:
“I see little difference between the common general knowledge (“CGK”) of one chemical engineer as identified above, and a team of such engineers. All engineers identified in the same way must by definition provide the same CGK.”
58. This does not of course remove the need for me to be mindful of the extent to which the experts called upon by the parties are representative of the person skilled in the art and, consequently, the weight to be afforded to the opposing views expressed by them.
59. In this regard I accept the submission advanced by Exxon that the field of the invention is global in nature. It would defy logic to suggest that knowledge of the critical need to remove sour species from natural gas is confined to the skilled person in Australia. Indeed, all declarants have attested to the imperative to maintain awareness of the state of the art both domestically and internationally. I therefore do not consider that Dr Northrop’s evidence can be disregarded altogether simply because he is based in the United States. Nevertheless, in coming from the perspective of an inventive worker in the field (see Northrop 1 at 1.4.1), it must be treated with a good deal of caution.
The known treatment of natural gas
60. The following represents a brief overview of the processes which as generally agreed upon by the parties are known for their use in the removal of sour species from natural gas. However, as will become apparent, the parties are in dispute as to the extent to which these processes were known to the person skilled in the art.
Physical processes
61. Absorption is the most common form of physical process used to remove carbon dioxide and hydrogen sulphide from natural gas, and utilises aqueous solutions of either a chemical or a physical liquid absorbent or “solvent”. Chemical solvent processes remove the sour species from the natural gas feed stream by chemical reaction with a material, generally an amine, in the solvent solution. Physical solvent processes are based on absorption by solubility alone without associated chemical reactions. Refrigerated methanol is a widely recognised physical solvent. There are also a number of hybrid processes which combine the effects of physical and chemical solvents such as Shell’s commercial Sulfinol process.
62. Other known physical processes include the use of adsorbents such as molecular sieves, and membrane separation using polymer-based gas permeable barriers.
Cryogenic processes
63. In contrast to physical removal processes, cryogenic processes generally involve cooling the natural gas feed stream to a temperature at which acid gases such as carbon dioxide either liquefy or solidify (freeze). A number of cryogenic processes are described at length in the evidence. These include the bulk fractionation process and the Ryan-Holmes process (PN-7: Jarrett, Fundamentals of gas fractionation, Hydrocarbon Processing, April 1983) (Jarrett). The bulk fractionation process is so-called because although it removes the bulk of the carbon dioxide, a substantial proportion of carbon dioxide remains in the treated natural gas stream, and consequently a further carbon dioxide removal stage such as a conventional solvent process must be employed if the treated gas stream is required to meet pipeline or liquefaction specifications (Tsesmelis 1 at [2.4.12]. In the Ryan-Holmes process, carbon dioxide is separated by deliberately suppressing its solidification.
64. Most relevantly for present purposes, cryogenic solidification processes also include what have been referred to in evidence as the controlled freeze zone (CFZ) and Cool Energy technologies. In short, the CFZ process is a cryogenic distillation technique for separating carbon dioxide and heavier hydrocarbons from methane which controls the freezing and melting of carbon dioxide in a specially designed section of an otherwise conventional distillation tower. This process was developed by Exxon and the base technology first patented in US 4,533,372 which was published in 1985 (Northrop 1 at [5.4.1] and [5.5.3]; PSN-10). The Cool Energy process was developed by Professor Robert Amin of Curtin University, WA, in collaboration with its commercial arm, Cool Energy Ltd (Tsesmelis 1 at [2.4.20]). The rights to this technology were subsequently acquired by Shell (CMT-17). An example of the Cool Energy process is disclosed in D1.
Common general knowledge
65. The notion of common general knowledge was described in MinnesotaMining andManufacturing Co v Beiersdorf (Australia) Ltd [1980] HCA 9; 144 CLR 253 at 292 as involving:
“… the use of that which is known or used by those in the relevant trade. It forms the background knowledge and experience which is available to all in the trade in considering the making of new products, or the making of making improvements in old, and it must be treated as being used by an individual as a general body of knowledge.”
66. The common general knowledge will encompass not only material that is retained in the memory of the skilled person, but also material that the person knows of, and to which they might refer as a matter of course, or habitually consult. This material could include, for example, standard texts and handbooks (ICI Chemicals & Polymers Ltd v Lubrizol Corporation Inc [1999] FCA 345; 45 IPR 577 at [112]).
67. The following represents what the parties have effectively agreed may be regarded as commonly known by those working in the relevant art:
The use of chemical solvents;
The use of physical solvents;
The use of hybrid solvation processes;
The use of separation membranes; and
The use of adsorbents.
68. Dr Northrop and Mr Tsesmelis are both strongly of the view that it was also commonly known to use each of the cryogenic processes outlined above to sweeten natural gas. Shell acknowledges at [153] of its submissions that the Ryan-Holmes process and the CFZ process formed part of the common general knowledge.
69. The position with respect to the status of the bulk fractionation process and the Cool Energy process is not so readily apparent.
70. In Dugan at [4.11] it is stated:
“In my experience as at [the priority date], it was not usual or conventional practice in LNG production to cool a sour gas to temperatures where carbon dioxide or other acid gases were likely to freeze. On the contrary, it was widely considered that it was undesirable to remove sour contaminants by a process which intentionally solidified the sour contaminants as there was a real operational risk that equipment would block up.”
71. Mr Dugan goes on to state (at [7.7] and [7.13]) that employing a process such as bulk fractionation was generally avoided in the art because of the risk of carbon dioxide solid formation. This line of reasoning is not relevant to the question of whether matter can be regarded as common general knowledge, and furthermore, is at odds with Shell’s acknowledgement that the CFZ process, which promotes the formation of carbon dioxide solids, had assimilated into common general knowledge. It is also inconsistent with the fact that Mr Dugan has on several occasions confirmed his awareness of, and described in detail, the nature of the bulk fractionation process (including its recognised drawbacks). This strongly suggests to me that this process was commonly known to him.
72. So far as the Cool Energy process is concerned, Mr Dugan admits that he was involved in managing the design, construction, instalment and commissioning of a pilot plant in Australia to conduct field tests of a Cool Energy process known as “Cryo-Cell”. At [7.17] he emphasises that “this was just a demonstration plant – not a commercial operation”. However, commercialisation is not of itself an indicator of common general knowledge. For its part Exxon has argued that the Cool Energy process was widely known and accepted in the art, firstly, because of the renown of Prof Amin and the reputation of Cool Energy Ltd and, secondly, because of its publication in a number of patent specifications such as those annexed as PSN-11 to PSN-13.
73. Exxon refers to a technical paper co-authored by Prof Amin titled “Advanced LNG Technology” which was allegedly published at an international conference held in Australia in December 2003 (CMT-10). The paper briefly discusses the laboratory test results of a process developed at Curtin University to remove sour species as part of the cryogenic process of liquefying natural gas. Prof Amin’s notoriety is not in issue here, but I am far from convinced that those engaged in the industry would as a consequence routinely study and familiarise themselves with work published by him. Interestingly, neither Dr Northrop nor Mr Tsesmelis actually state that they were aware of the aforementioned technical paper at the relevant date. Whatever the case may be, there is no evidence of its general acceptance and assimilation by persons skilled in the art.
74. As to Exxon’s second line of argument, it is well settled that individual patent specifications and their contents do not normally form part of the common general knowledge (General Tire at 482). Exxon has adduced evidence that the skilled person would consult patent literature, but I think this evidence simply relates to the enquiry that would be undertaken when searching for prior art information of the kind referred to in subsection 7(3). It does not substantiate that patent literature is indicative of common general knowledge in the field of the invention (cf. Minnesota Mining at 294). As a matter of logic, this finding extends to each item of patent literature relied on by Exxon, and not just those identified as relating to the Cool Energy process.
75. I find that although the Cool Energy process may have been known in the art, it was not common.
Is the claimed invention obvious
76. Exxon relies on the common general knowledge taken alone or together with either D1 or the document RC Haut et al, Development and Application of the Controlled Freeze Zone Process, SPE Production Engineering, pp 265-271, August 1989 (D5). It has become apparent from Northrop 3 that Exxon also relies on PSN-21 and PSN-22.
Common general knowledge alone
77. Mr Dugan and Mr Tsesmelis have both attested to the conservative nature of the gas processing industry. At [7.3] Mr Dugan states:
“… I work in a very conservative industry which seeks to minimise its technical risk, and particularly seeks to minimise its occupational health and safety risk associated with an operational natural gas processing plant. In particular, given the very significant costs with the development of technologies in this industry, it is standard practice to seek to rely on or adapt existing technologies rather than develop new or commercially untested technologies. Accordingly, I would look for tried and true solutions. By ‘tried and true solutions’ I refer to technologies that have been employed successfully in a commercial plant and which offer minimal technical and operational risk.”
78. On this basis Mr Dugan reasons that if faced with the problem of improving the removal of sour species from natural gas, the skilled person would utilise the existing and proven methods of either adsorption using molecular sieves or absorption using amines or physical solvents, rather than a process which intentionally solidified the sour species. In response, Tsesmelis 2 at [5.6] states:
“The industry is indeed conservative and cautious when introducing new technology. The technical, occupational, health and safety risks associated with any new process would be carefully evaluated as part of any research and development effort before further process development, laboratory scale, pilot plant and eventually commercial plant designs were considered. However, this conservatism has not led to a lack of research and development of new technologies for natural gas processing.”
79. Northrop 3 at [13.2] observes that if Mr Dugan’s opinion truly reflected the nature of the industry, it “would never make any progress”. I am persuaded by Exxon’s evidence in this matter. The imperative to remove sour species from natural gas has long been recognised in the art and continues to be driven by the increasing reliance on gas streams sourced from natural gas reserves having high concentrations of carbon dioxide. As acknowledged even by the present specification and Dugan at [3.16], none of the “tried and true” physical removal processes such as absorption are economically viable for treating natural gas streams with high carbon dioxide content. I therefore consider that the person skilled in the art would not discount the commonly known cryogenic processes as possible solutions to the problem addressed.
80. At [125] of its reply submissions Exxon asserts that:
“The problem sought to be solved involves the creation of an improved process for the treatment of a natural gas feedstock containing relatively high concentration of CO2, which reduces concentration of the CO2 to levels that are suitable for routine liquefaction of the gas stream to produce LNG. The routine solution to this problem is to combine existing unit operations which are accepted from the common general knowledge.”
81. The same avenue of attack is pursued in Northrop 1 where Dr Northrop contends that the claimed invention “involves nothing more than joining existing technologies”. At [6.2.1] and [6.4.6] he broadly summarises these as a carbon dioxide condensation and/or solidification process, followed by a cold solvent process, followed in turn by routine liquefaction. He submits with respect to the first process that “[these] can be readily integrated into an LNG facility and thus readily practiced in combination with other unit operations, such as absorption methods.”
82. Shell has challenged the case put by Exxon. It complains that in dissecting the claimed invention into its constituent elements, Exxon is impermissibly relying on hindsight analysis. I share the same concerns. Where, as here, the question of inventiveness arises in respect of an invention involving a combination of features, it is the inventiveness of the combination as a whole that must be examined: the “inventiveness of particular integers is irrelevant to the inventiveness of a combination of them” (LockwoodSecurity Products Pty Ltd v Doric Products Pty Ltd [2004] HCA 58; 217 CLR 274; 212 ALR 1 at [78]). In any event, the evidence does not support Exxon’s chief contention that “CFZ is readily integrated into an LNG plant” (Northrop 1 at [6.4.6]).
83. There is no dispute that it was common practice in the art to serially combine a number of gas processing stages in those instances where initial treatment of the gas stream was unable to remove sour species to sales or liquefaction specifications (Tsesmelis 1 at [2.4.39(b)]; Dugan at [4.13]; Northrop 2 at [2.6]). The only multi-stage process confirmed by the evidence to be commonly known is one in which bulk fractionation is typically followed by an absorption process (Northrop 1 at [5.2.3]). Notably, the known multiple-stage processes were conducted under ambient conditions, not at cryogenic temperatures, and upstream of a treated gas liquefaction plant. In other words, the natural gas feed stream is conventionally sweetened in a separate “front-end” gas treatment unit.
84. In contrast, Shell submits that the claimed invention involves the integration of a gas sweetening process with an LNG production process. As conveniently put in Dugan at [4.50]:
“Essentially, two distinct sweetening processes in serial combination [sic: have] been interposed within LNG refrigeration circuits … Convention [at the priority date] and even now is to provide the sweetening process as a discrete treatment upstream of the LNG train, operating at ambient temperatures, not cryogenic temperatures. It is not a matter of routine to decouple the refrigeration units in an LNG refrigeration train and to insert a cryogenic sweetening unit between them”
85. Exxon has not seriously challenged this characterisation of the claimed invention. In Northrop 3 at [11.6], Dr Northrop relies on his recollection of a memo on “integrating CFZ with LNG” which he had tried to submit to Exxon in 2008 as confirmation that the dual features of decoupling and insertion mentioned above were not necessarily “a new idea”. This bald assertion does not on any view constitute evidence of common general knowledge. Furthermore, none of the documents on which Dr Northrop relies (including PSN-7 and D5) to further support the contention that it was obvious to integrate the known processes of CFZ and liquefaction to arrive at the claimed invention have been proven in evidence to be items of common general knowledge.
Common general knowledge and D1
86. I have already found that D1 does not disclose a number of features of the claimed invention. The evidence adduced by Exxon simply does not establish that the skilled person armed with common general knowledge would as a matter of routine have supplied these missing features. As noted above, the claimed invention does not reside in the mere aggregation of commonly known natural gas processing stages. Consequently, it is unnecessary to consider whether this document would have been ascertained, understood and regarded as relevant.
Common general knowledge and D5
87. D5 describes the CFZ process and compares it to solvent or additive gas treatment processes. It additionally gives examples of potential CFZ application, including integration into LNG production. However, D5 does not provide any indication of how such integration might be achieved, or whether the feasibility of this proposal has been tested in the laboratory or field. I therefore fail to see how the addition of common general knowledge to D5 could be said to lead to the claimed invention. Consequently, it is unnecessary to consider whether this document would have been ascertained, understood and regarded as relevant.
Common general knowledge and PSN-21/PSN-22
88. After being admitted into the proceedings as new information, on closer scrutiny PSN-21 does not advance Exxon’s case. I note in particular that the product gas of the integrated CFZ conceptual design reviewed in PSN-21 is sales gas and not LNG. PSN-22 is even less relevant since it teaches away from the formation of carbon dioxide solids. Consequently, it is unnecessary to consider whether these documents would have been ascertained, understood and regarded as relevant.
89. This ground of opposition therefore does not succeed.
Manner of manufacture
90. Exxon objects that claims 24 to 28 are directed to a mere scheme or plan which has been traditionally held as belonging to the fine arts and therefore excluded from patentability. Exxon further criticises these claims as being “directed to impermissible collocations in which there is no working inter-relationship between the financial method and the technical process and apparatus”. I do not consider that claims 24 to 28 can be rejected on this basis. As submitted by Shell at [264]-[266] (with original emphasis):
“Exploitation of the process and apparatus defined … facilitates a reduction of greenhouse gas emissions in comparison with conventional technologies for liquefaction of a gas stream contaminated by sour species [specification at page 35, lines 15-18]. The reduction in greenhouse gas emissions is achieved by separating carbon dioxide from the gas stream in liquid form. The liquid carbon dioxide may be directly pumped to a liquid carbon dioxide sequestration site, or disposed of for retail sale. Additionally, prior to sequestration or storage, the liquid carbon dioxide may be used as a cooling stream in any one or more of the heat exchangers of the apparatus to conserve energy within the apparatus. The reduction of greenhouse gas emissions is an artificially created state of affairs which is inherently incorporated within amended claims 25-28. It is no different to the improved tract or stratum of land referred to by the High Court in NRDC. The creation of a financial instrument tradable under a greenhouse gas Emissions Trading Scheme is only made possible by reducing the greenhouse gas emissions when gas is subject to the processes, or treated with the apparatus, defined by amended claims 1-24. The financial instrument is inherently and inextricably linked to, and cannot be created without, a reduction in greenhouse gas emissions resulting from the claimed method and apparatus ... The financial instrument created by the method of amended claims 25-28 is not mere information or an abstract idea. Rather, the financial instrument is a tangible asset with a tangible economic value which can be traded under an Emissions Trading Scheme.”
91. I am persuaded by this submission, noting also that the patentability of the claims to which claims 25-28 are linked is not in issue.
92. This ground of opposition accordingly does not succeed.
Other considerations
93. Mr Fitzpatrick drew my attention to the fact that claims 8 and 9 incorrectly refer to step (d) rather than step (e), and that claim 17 should refer to a temperature of minus 162oC. Exxon has not raised any of these issues, and nor do they in my opinion lead to ambiguity.
Conclusion
94. I have found that the opposition does not succeed on any of the grounds relied on. The opposition is therefore dismissed.
Costs
95. Exxon has not been successful and I can see no reason why costs should not follow the event. I therefore award costs against Exxon.
O L Haggar
Delegate of the Commissioner of Patents
0
1
0