ExxonMobil Upstream Research Company v Shell Internationale Research Maatschappij B.V - [2015] APO 39

IP AUSTRALIA
AUSTRALIAN PATENT OFFICE
ExxonMobil Upstream Research Company v Shell Internationale Research Maatschappij B.V. [2015] APO 39
Patent Application: 2008213739

Title:Process and apparatus for depleting carbon dioxide content in a natural gas feedstream containing ethane and C3+ hydrocarbons

Patent Applicant:                   Shell Internationale Research Maatschappij B.V.
Opponent:  ExxonMobil Upstream Research Company
Delegate:  Rhys Munzel
Decision Date:  15 July 2015
Hearing Date:  29 April 2015, in Melbourne

Catchwords: PATENTS – method and apparatus for cryogenic removal of CO₂, ethane and C3+ hydrocarbons from natural gas – lack of novelty and inventive step alleged – certain apparatus claims lack novelty and an inventive step – costs – amendment of the Statement of Grounds and Particulars two weeks before the hearing – matter did not turn on the amended Particular – costs awarded against Shell

Representation: Patent applicant: Mr Ben Fitzpatrick of counsel, instructed by Dr Mary Turonek and Dr Marcus Caulfield of FB Rice
Opponent: Mr Ian Horak of counsel, instructed by Mr Richard Baddeley

IP AUSTRALIA
AUSTRALIAN PATENT OFFICE
Patent Application: 2008213739

Title:Process and apparatus for depleting carbon dioxide content in a natural gas feedstream containing ethane and C3+ hydrocarbons

Patent Applicant: Shell Internationale Research Maatschappij B.V.
Date of Decision: 15 July 2015
DECISION
The opposition succeeds on the grounds that:
·claims 13-16 are not novel; and
·claims 13-16 lack an inventive step.

I allow Shell Internationale Research Maatschappij B.V. eight weeks from the date of this decision to propose amendments to overcome these deficiencies.
I award costs according to Schedule 8 against Shell Internationale Research Maatschappij B.V.
REASONS FOR DECISION
Background

Patent application 2008213739 (“the application”) in the name of Shell Internationale Research Maatschappij B.V. (“Shell”) was examined and accepted by the Commissioner, and subsequently opposed by ExxonMobil Upstream Research Company (“Exxon”). Shell requested examination before 15 April 2013, which means that substantive amendments to the Patents Act[1] brought about by the Intellectual Property Laws Amendment (Raising the Bar) Act[2] do not apply to this opposition.
[1] 1990 (Cth) (“the Act”).
[2] 2012 (Cth) (“the Raising the Bar Act”).
Exxon and Shell each rely on expert evidence in the form of declarations. Exxon’s evidence in support consists of declarations by:
·     Richard Baddeley dated 5 December 2012 (“Baddeley 1”) with Exhibits RHB1-RHB17; and dated 18 September 2013 (“Baddeley 2”) with Exhibit RHB18;
·     Costa Tsesmelis dated 5 June 2013 (“Tsesmelis 1”) with Exhibits CMT1-CMT17; and dated 2 October 2013 (“Tsesmelis 2”) with Exhibits CMT18-CMT28C;
·     Robert Denton dated 25 September 2013 (“Denton 1”) with Exhibits RDD1-RDD7; and
·     Jaime Valencia dated 27 September 2013 (“Valencia 1”) with Exhibits JAV1-JAV7.
Shell’s evidence in answer consists of a declaration by Craig Dugan dated 17 June 2014 (“Dugan 1”) with Schedule A and Exhibits CD1-CD3.
Exxon’s evidence in reply consists of declarations by:
·     Jaime Valencia dated 15 September 2014 (“Valencia 2”) with exhibits JAV8-JAV12;
·     Robert Denton dated 15 September 2014 (“Denton 2”) with Exhibits RDD8-RDD10; and
·     Costa Tsemelis dated 19 September 2014 (“Tsesmelis 3”) with Exhibits CMT29-CMT33.
The hearing occurred on 29 April 2015. Ian Horak of counsel, instructed by Richard Baddeley of Watermark Patent and Trade Marks Attorneys, attended on behalf of Exxon. Ben Fitzpatrick of counsel, instructed by Mary Turonek and Marcus Caulfield of FB Rice, attended on behalf of Shell. On 10 April 2015 Shell filed a request to amend the Statement of Grounds and Particulars to cite for novelty a prior art document which was previously only cited for s 7(3) inventive step. I allowed each party an opportunity to file further written submissions in relation to that document. Shell filed its submissions on 20 May 2015 and Exxon filed its reply submissions on 27 May 2015.
Onus
As I noted above substantive amendments brought about by the Raising the Bar Act[3] do not apply. The onus therefore rests with Exxon to clearly establish its case. In establishing that any ground of opposition succeeds, the Commissioner should be “clearly satisfied that the patent, if granted, would not be valid.”[4]
[3] 2012 (Cth).
[4] F. Hoffman-La Roche AG v New England Biolabs Inc [2000] FCA 283, [67].
Grounds of opposition
Exxon submits that the invention claimed lacks novelty and an inventive step.
The nature of the disclosed invention
Before construing the patent specification (“the specification”), I note what Middleton J said in Eli Lilly and Company Limited v Apotex Pty Ltd:[5]
“It is well settled that the Court should, from the outset, approach the task of patent construction with a generous measure of common sense. The Court must place itself in the position of a person skilled in the relevant art, being the subject matter of the patent. From this perspective, the patent is to be read as a whole, in the context of the specification and in light of the prevailing common general knowledge and state of the relevant art at the priority date.”
The background art and identified problem
[5] [2013] FCA 214, 100 IPR 451, [139].
The invention relates to a process for depleting CO₂ content in natural gas containing ethane and C3+ hydrocarbons.[6] As set out in the background art, while “sales gas” has an allowable CO₂ content of 2-4%,[7] natural gas reserves may contain much higher levels.[8] Several established methods to separate the CO₂ (also described as “sweetening” the natural gas) include: solvents, amine absorption systems, membrane technologies, and hybrid systems comprising a serial combination of these processes.[9]
[6] The present specification, page 1 lines 7-14.
[7] Ibid, page 1 lines 23-25.
[8] Ibid, page 1 lines 18-23, page 1 line 32 to page 2 line 6.
[9] Ibid, page 1 lines 26-31.
Many natural gas reserves comprise a CO₂ content of 60% or more.[10] While established separation methods can reduce the CO₂ content of such gases to less than 4%, the high load on these systems “frequently results in high capital and operational costs and development of the reserve is generally considered as economically unviable.”[11]
[10] Ibid, page 1 lines 32-33.
[11] Ibid, page 1 line 33 to page 2 line 6.
US 5983663 is described as providing a “particularly economical” method for bulk removal of CO₂ from natural gas containing in excess of 10% CO₂.[12] Two shortcomings of the disclosed process are identified:
· it is not suited to reducing CO₂ content to sales gas specification and must be supplemented with a further CO₂ absorption step;[13] and
· it does not address removal of CO₂ in the presence of ethane and higher hydrocarbons.[14] CO₂ and ethane form an azeotrope while a proportion of C3+ hydrocarbons tend to co-condense with CO₂ at typical conditions.[15] These components are commercially valuable and their recovery involves downstream processing, increasing capital and operating costs.[16]
[12] Ibid, page 2 lines 8-13.
[13] Ibid, page 2 lines 14-19.
[14] Ibid, page 2 lines 33 to page 3 line 5.
[15] Ibid, page 2 lines 20-27.
[16] Ibid, page 2 lines 28-32.
A group of patent documents: WO 2003/062725; WO 2004/070297; and WO 2007/030888 are referred to as teaching that CO₂ can be separated from natural gas to less than 4% by solidifying or liquefying the CO₂.[17] However, the specification notes that:
“It has become apparent from extensive field tests undertaken by the inventors of the present invention that the processes described therein are performed under thermodynamic factors which are limited to processing a feedstream with a carbon dioxide content of less than 15 to 25%, depending on the composition of the natural gas feedstream, to achieve a treated gas stream with a carbon dioxide content of between 2-4%.”[18]
[17] Ibid, page 3 lines 6-12.
[18] Ibid, page 3 lines 12-20.
A need in the art is then identified:
“to develop an economical process which can bulk remove sour species, such as carbon dioxide and hydrogen sulphide, from a feedstream with high carbon dioxide content of up to 60% or more containing ethane and high hydrocarbons to obtain a treated gas stream with a carbon dioxide content of between 2-4%.”[19]
The summarised invention
[19] Ibid, page 3 lines 21-27.
The invention is summarised in aspects (i.e. consistory statements) consistent with the claims of the specification as originally filed and accepted. The broadly disclosed invention relates to a process and apparatus for removing CO₂ from a natural gas feedstream containing ethane and higher hydrocarbons, the process comprising:
·     cooling the natural gas feedstream to produce a liquid stream of CO₂, ethane and higher hydrocarbons and a gas stream of reduced CO₂ concentration;
·     separating the liquid stream from the gas stream;
·     cooling the separated gas stream to produce a sweetened natural gas stream and a second liquid containing liquid carbon dioxide and/or carbon dioxide solids; and
·     separating the sweetened natural gas stream from the second liquid.[20]
The preferred embodiment
[20] Ibid, page 4 lines 9-26, page 11 line 31 to page 12 line 14.
I have prepared the following figure to explain the preferred embodiment:
Feed gas passes through dehydration unit 12.[21] Dehydrated gas is then compressed in compressor 14 to 5,500-7,000 kPa.[22] Compressed gas passes through a cooling apparatus 20 comprising several heat exchangers in series and a chiller to provide cooled gas at -15°C to -20°C.[23] Some of the cooled gas condenses and the resulting liquid and vapour phases are separated in separator 30 before passing to separate trays of fractionating column 16.[24] As it becomes relevant later, I note that the liquid stream from the separator 30 is described as comprising CO₂, ethane, C3+ hydrocarbons and potentially some methane.[25] As a matter of logic, it makes sense to me that this stream would contain a substantial amount of CO₂ and methane as there is no reason I can see to introduce a stream of pure ethane and C3+ hydrocarbons to the fractionating column 16.
[21] Ibid, page 15 line 17 to page 16 line 4.
[22] Ibid, page 16 lines 60-20.
[23] Ibid, page 16 lines 21 to page 18 line 30.
[24] Ibid, page 18 lines 1-20.
[25] Ibid, page 18 lines 10-14.
The fractionating column 16 produces a gas stream of reduced CO₂ content, and a liquid stream containing liquid CO₂, ethane and C3+ hydrocarbons.[26] The liquid stream may be further processed to recover the ethane and C3+ hydrocarbons.[27] The preferred upper limit of CO₂ content in the gas stream is in the range of 20% to 25%.[28]
[26] Ibid, page 18 lines 21-26.
[27] Ibid, page 19 line 23 to page 20 line 11.
[28] Ibid, page 18 lines 31-34.
The gas stream leaving the fractionating column is cooled in a heat exchange train 42 to just above the CO₂ solids formation temperature, and then further cooled in a cooling vessel 44 to form solid CO₂.[29] Cooling in the cooling vessel 44 is achieved by expanding the gas as it enters the vessel using a Joule-Thomson valve or other suitable gas expander.[30]
[29] Ibid, page 21 lines 1-8.
[30] Ibid, page 21 line 30 to page 22 line 6.
A small amount of hydrocarbons will condense in the cooling vessel 44, thereby forming a slurry of natural gas liquid and CO₂ solids.[31] The slurry can accumulate in a lower portion of the cooling vessel under gravity 44.[32] The accumulated slurry can be heated to melt the CO₂.[33] The resulting liquid CO₂ stream exits the cooling vessel 44 where it is combined with the CO₂ stream provided by the first separation step.[34]
[31] Ibid, page 22 lines 22-28.
[32] Ibid, page 22 line 33 to page 23 line 2.
[33] Ibid, page 23 lines 4-22.
[34] Ibid, page 23 line 29 to page 24 line 2.
Optionally, subsequent to separating the sweetened natural gas from the second liquid, the sweetened natural gas may be contacted with a solvent to further remove CO₂.[35] The CO₂ is more soluble in the solvent than in the natural gas stream.[36] Relevantly, ethane and C3+ hydrocarbons are listed as suitable solvents.[37]
[35] Ibid, page 8 lines 24-30.
[36] Ibid, page 8 lines 30-32.
[37] Ibid, page 8 line 32 to page 9 line 5.
Construing the claims
The correct approach to the construction of claims was discussed by Bennett J in H Lundbeck A/S v Alphapharm Pty Ltd:[38]
"Words in a claim should be read through the eyes of the skilled addressee in the context in which they appear. Words used in a specification are to be given the meaning which the person skilled in the art would attach to them, having regard to his or her own general knowledge and to what is disclosed in the body of the specification … while the claims define the monopoly claimed in the words of the patentee's choosing, the specification should be read as a whole … it is not permissible to read into a claim an additional integer or limitation to vary or qualify the claim by reference to the body of the specification … terms in the claim which are unclear may be defined or clarified by reference to the body of the specification".
[38] [2009] FCAFC,70, 81; (2009) IPR 228, [118]-[120].
Post-acceptance amendments to the claims were allowed on 21 May 2014. As a result the specification ends with 20 claims. Claims 1-3 and 13 are independent claims while claims 19 and 20 rely on references to the description. Claim 1 provides as follows:
“A process for depleting carbon dioxide content in a natural gas feedstream containing ethane and higher hydrocarbons, comprising the steps of:
(a)   cooling the natural gas feed stream under a first set of temperature and pressure conditions arranged to produce a liquid stream of carbon dioxide, ethane and C3+ hydrocarbons and a gas stream having a reduced carbon dioxide concentration;
(b)   separating said liquid stream from said gas stream;
(c)   cooling the gas stream separated in step (b) in a cooling vessel to a temperature at or below an operating temperature at which carbon dioxide solids are formed by expanding the gas stream as it is being introduced to the cooling vessel; and,
(d)   separating the sweetened natural gas stream from a second liquid containing liquid carbon dioxide and/or carbon dioxide solids.”
Claim 2 defines a similar process to claim 1, however the cooling step defined in step (c) is achieved by spraying the gas with a sub-cooled liquid as it is being introduced to the cooling vessel. Claim 3 differs from claims 1 and 2 in that the cooling step is achieved by both expanding the gas stream and spraying it with a sub-cooled liquid as it is introduced to the cooling vessel. Claim 13 defines an apparatus as follows:
“An apparatus for depleting the carbon dioxide content in a natural gas feedstream containing ethane and higher hydrocarbons, the apparatus comprising:
a first cooling apparatus for cooling the natural gas feedstream under a first set temperature and pressure conditions arranged to produce a liquid stream of carbon dioxide, ethane and C3+ hydrocarbons and a gas stream having a reduced carbon dioxide concentration;
a separator for separating said liquid stream from said gas stream; and
a cooling vessel having an expansion device located at and/or defining a first inlet, the first inlet being in fluid communication with the separator and arranged to introduce the gas stream separated from the separator into the cooling vessel to produce carbon dioxide solids, a second inlet for introducing a sub-cooled liquid into the cooling vessel, a first outlet for the sweetened natural gas stream and a second outlet for a second liquid.”
A liquid stream of carbon dioxide, ethane and C3+ hydrocarbons
Unlike the natural gas feedstream and the second liquid stream, the liquid stream arising from cooling the natural gas feed stream (the first liquid stream) is exhaustively defined as being “of” certain components. Purposively this stream can contain trace impurities, while conversely each listed component should be found in higher than trace amounts. As an example a stream containing 99.98% ethane may be purposively viewed as a stream “of” ethane, in which any CO₂ content would be at negligible amounts. I otherwise note that CO₂ need not be the major component of that liquid stream.
Cooling the gas stream separated in step (b)…
Claims 1-3 define that the gas separated in step (b) is cooled to a temperature at or below that which CO₂ solids are formed by:
· expanding the gas stream as it is introduced to the cooling vessel and/or
· spraying the gas stream with a sub-cooled liquid as it is introduced to the cooling vessel.
Use of the term “by” indicates that a required temperature is achieved by the defined expansion and/or spraying step.
Vessel
Shell cited an earlier opposition[39] between Shell and Exxon in which the Delegate noted:
“it was agreed by both parties that the dictionary definition of a ‘vessel’ could be used ... JAV-31 defines vessel: as a container used as a structural envelope.”
[39] Exxon Mobil Upstream Research Company v Shell Internationale Research Maatshappij B.V. [2012] APO 92.
I add that the defined vessel is provided to contain and cool a gas stream. It is purposively therefore a gas vessel, for example a pressure vessel.
Novelty
The general test for lack of novelty is the reverse infringement test. The classic formulation of this test was given by Aickin J in Meyers Taylor Pty Ltd v Vicarr Industries Ltd:[40]
“The basic test for anticipation or want of novelty is the same as that for infringement and generally one can properly ask oneself whether the alleged anticipation would, if the patent were valid, constitute an infringement.”
[40] [1977] HCA 19 at [20], 137 CLR 228, 235.
This test is satisfied if the alleged anticipation discloses all the essential features of the invention as claimed.[41] On the level of disclosure required Australian courts have often cited, with approval, the words of the UK Court of Appeal in The General Tire & Rubber Company v The Firestone Tyre and Rubber Company Limited:[42]
“if carrying out the directions contained in the prior inventor's publication will inevitably result in something being made or done which, if the patentee's patent were valid, would constitute an infringement of the patentee's claim, this circumstance demonstrates that the patentee's claim has in fact been anticipated.
If, on the other hand, the prior publication contains a direction which is capable of being carried out in a manner which would infringe the patentee's claim, but would be at least as likely to be carried out in a way which would not infringe the patentee's claim, the patentee's claim will not have been anticipated, although it may fail on the ground of obviousness. To anticipate the patentee's claim the prior publication must contain clear and unmistakable directions to do what the patentee claims to have invented”
[41] Nicaro Holdings Pty Ltd v Martin Engineering Co (1990) 91 ALR 513, 517.
[42] [1972] RPC 457, 485-486 (“General Tire”).
Exxon relies on two documents to establish that the invention lacks novelty:
D4WO2004/070297 A1 (Shell Internationale Research Maatschappij B.V.) 17 August 2004; and
D14Haut, R., et al., “Development and Application of the Controlled-Freeze-Zone Process” SPE Production Engineering (1989) 265.
D4
Exxon submits that claims 1-5, 8, 9, 11-16, 18 and 19 lack novelty in view of D4. D4 relates to sequentially dehydrating and sweetening natural gas. Fig. 2 of D4 exemplifies the disclosed process and is reproduced below.
A wet feedgas stream 15 is fed to a first flash tank 16 in which liquid hydrocarbons are condensed and removed.[43] The exiting gas stream 20 is cooled before entering a first vessel 12 where it is further cooled such that hydrates are formed and removed to separate water from the gas.[44] Dry sour gas 35 exiting the first vessel 12 is cooled via heat exchanger 36 and fed to a second flash tank 40 where condensate 43 is removed.[45] The dry sour gas 45 is then further cooled and expanded via a Joule-Thomson valve 48 defining the inlet to a second vessel 14.[46] Alternatively the dry sour gas may be cooled via spraying it with a sub-cooled liquid 49 as it enters the second vessel 14, or by both expansion and spraying.[47] Solid sour species form in the second vessel 14 and a dry sweetened gas stream 65 exits via outlet 62, while a liquid stream containing melted sour species exits via outlet 52.[48]
[43] D4, page 5 lines 1-3.
[44] Ibid, page 5 line 26 to page 6 line 15.
[45] Ibid page 7 lines 7-25.
[46] Ibid, page 9 lines 1-14.
[47] Ibid, page 9 line 32 to page 10 line 8.
[48] Ibid, page 9 lines 9-14.

There is undisputed evidence that the second vessel 14 provides a cooling vessel in which solid CO₂ is formed and separated according to the present claims.[49] Exxon submits that the heat exchanger 36 and the second flash tank 40 also provide the first cooling and separating steps in which a liquid stream (the condensate) of CO₂, ethane and C3+ hydrocarbons is removed. Shell disputes whether the liquid stream would inherently contain CO₂.
[49] See for example Dugan 1, [5.25] and [5.26].
I initially note a similarity between the heat exchanger 36 and second flash tank 40 of D4, and the cooling apparatus 20 and separator 30 of the specification. Each are provided such that natural gas containing CO₂, ethane and C3+ hydrocarbons is cooled, and condensed liquids are separated from the remaining gas. In D4 the condensate is described as containing C2-C4 hydrocarbons, [50] while in the specification it is described as comprising CO₂, ethane, C3+ hydrocarbons and potentially some methane.[51] The specification also notes that liquid ethane and C3+ hydrocarbons are an absorbent for CO₂, in that CO₂ is more soluble in those components than in natural gas.[52] Craig Dugan declared that, when using cryogenic distillation processes to remove ethane and C3+ hydrocarbons from natural gas, the CO₂ may “split” between recovered ethane and the top product gas, potentially affecting specifications for both products.[53] Evidence supporting this is found in D14, in which a stream of ethane and C3+ hydrocarbons condensed from natural gas contains 2 mol% CO₂.[54] I surmise that it is possible to co-condense not insubstantial amounts of CO₂ when condensing ethane from natural gas. It therefore becomes a matter of determining whether it is inherent to the process disclosed in D4.
[50] D4, page 10 line 21 to page 11 line 4.
[51] The specification, page 18 lines 10-14.
[52] Ibid, page 8 line 32 to page 9 line 5.
[53] Dugan 1, [3.2.2]
[54] D14, Table 1.
Regarding conditions in the second vessel, I consider D4 to disclose:
·     the temperature is somewhere above -56°C and below that required to condense ethane and C3+ hydrocarbons and provide a sub-cooled liquid 26 for the first vessel 12;[55]
·     the pressure must inherently be somewhere between 65-120 bar and 20-50 bar. This takes into account that:
o   the disclosed pressure upstream of the expansion device 24 is 75-130 bar;[56]
o   the disclosed pressure of the dry gas stream exiting the first vessel 12 is 10-30 bar lower than that;[57] and
o   the disclosed pressure of the dry sweetened gas exiting the second vessel is 20-50 bar;[58] and
·     the dry gas stream exiting the first vessel 12 inherently contains CO₂ in quantities worth removing (otherwise a CO₂ removal step would not be required).
[55] D4, page 7 lines 7-13.
[56] Ibid, page 4 lines 29-33.
[57] Ibid, page 6 lines 4-10.
[58] Ibid, page 9 lines 15-20.
Mr Tsesmelis inferred that the dry gas stream exiting the first vessel 12 could be “rich” (containing more than 5% ethane and C3+ hydrocarbons) and could contain 25-50% CO₂.[59] He inferred this because D4 did not explicitly preclude such conditions.[60] Mr Tsesmelis then ran a series of calculations using HYSYS®[61] with which he determined that:
“for the range of pressure and temperature conditions producing the two-phase flow to flash tank 40, where condensed C2-C4 hydrocarbons are formed, some portion of the CO₂ in the dry sour gas feed is also condensed with the hydrocarbon liquid. The lower the temperature the more CO₂ is condensed.”[62]
[59] Tsesmelis 3, [10.7], [10.8].
[60] Ibid, [10.8].
[61] Proprietary chemical process simulation software produced by Aspen®.
[62] Tsesmelis 3, [10.9].
Shell contests Mr Tsesmelis’ conclusion. Shell submits:
·     Mr Tsesmelis provided no evidence of what gas compositions were used in his simulations; in particular the initial CO₂ content of the natural gas, and the amount of CO₂ condensing into the liquid stream;
·     Mr Tsesmelis presumed a rich gas feed stream having a high CO₂ content when there is no reason to necessarily infer this. The PSA may equally treat a feedgas having a lower CO_2, ethane, and C3+ content. Shell submits that Mr Tsesmelis’ presumptions highlight the lack of an inevitable content of CO₂ in the liquid stream; and
·     Mr Tsesmelis noted that “some portion” of CO₂ is condensed, however the invention is not directed to removal of inconsequential amounts of CO₂ with ethane and C3+ hydrocarbons.
I share some of Shell’s concerns. I do not infer that a high CO₂ content of 25-50% is necessarily disclosed in D4. The specification teaches that the process of D4 was found thermodynamically limited to a CO₂ content below 15-25%.[63] Further, while some amount of C2-C4 hydrocarbons must be present to separate from the second flash tank 40, I am not satisfied that the natural gas feedstream must necessarily be rich. Finally, I am unclear whether “some portion” constitutes a substantial or a trace amount of condensed CO₂. This may have been clarified if results of the HYSYS simulations were provided in evidence.
[63] The specification, page 3 lines 12-20.
Exxon further submits that the existence of an ethane-CO₂ azeotrope means that condensation of some CO₂ must occur whenever ethane is condensed. Mr Tsesmelis referred to one of his annexed Exhibits (CMT-4) which states that the azeotrope generally occurs at a composition of around 67% CO₂: 33% ethane.[64] I take from reviewing Fig. 3 of CMT-4 that ethane and CO₂ form a “positive azeotrope”, meaning that partial evaporation would take the evaporated gas closer to the azeotrope while partial condensation would take the condensed liquid away from it. As such I am not satisfied the azeotrope is relevant to the separation occurring in the second flash tank 40.
[64] A. S. Holmes, J. M. Ryan, “Process improves acid gas separation” Hydrocarbon Processing (1982) 131.
I am satisfied that CO₂ will generally co-condense (or otherwise absorb) to some degree when condensing ethane and higher hydrocarbons from natural gas. Conditions relevant to the degree of co-condensation would include temperature, pressure, and feed gas composition. However I am not satisfied that, at all conditions the PSA may reasonably apply when following the directions of D4, the CO₂ condensed would be at greater than trace amounts. Exxon have not established that D4 provides clear and unmistakeable directions resulting in a liquid stream as defined. Exxon have therefore not established that process claims 1-5, 8, 9, 11, 12 and 19 lack novelty in view of D4.
Regarding apparatus claim 13 I am satisfied it is possible depending on processing conditions to separate a liquid stream of CO₂, ethane and C3+ hydrocarbons in the second flash tank 40. I again note the similarity between the heat exchanger 36 and second flash tank 40 of D4, and the cooling apparatus 20 and separator 30 of the specification. I am comfortably satisfied that there is no reason the heat exchanger 36 and second flash tank 40 cannot achieve the temperature and pressure conditions necessary for co-condensation of a not-insubstantial amount of CO₂. Exxon have established that claim 13 lacks novelty in view of D4.
Claim 14 appends from claim 13 and defines that the second inlet is located above the first inlet and comprises a plurality of spray nozzles. As disclosed in D4 the inlet 49 for the sub-cooled liquid is provided above the inlet 46 for the dry natural gas and comprises nozzles.[65]
[65] D4, page 10 lines 9-10.
Claim 15 appends from claim 14 and defines that the second inlet is alternatively and/or additionally arranged to introduce a liquid solvent into the cooling vessel. As discussed in the present application a suitable liquid solvent might be ethane. D4 discloses spraying the natural gas with a sub-cooled liquid containing ethane which would provide some solvation of gaseous CO₂.[66]
[66] Dugan 1, [5.28].
Claim 16 appends from any of claims 13-15 and defines that the gas expansion device comprises a Joule-Thomson valve, turbo expander, or a serial combination thereof. This feature is disclosed in D4 in relation to gas expansion device 48.[67]
[67] D4, page 9 lines 3-7.
Claim 17 appends from claim 15 and defines that the cooling vessel is provided a liquid-gas contactor to facilitate contact of the liquid solvent with the natural gas stream. A liquid gas contactor is not disclosed in D4. Claim 18 appends from claim 17 and therefore also claims matter that is not disclosed.
Claim 19 defines an apparatus with reference to the disclosed example and figures. D4 does not disclose an apparatus consistent with the example and figures. In particular, a bulk fractionator, exemplified in the specification as the relevant separator, is not disclosed in D4.
Exxon have established that claims 13-16 lack novelty in view of D4.
D14
Exxon submits that claims 2 and 4-10 lack novelty in view of D14. D14 describes the Controlled Freeze Zone (“CFZ”) process of sweetening natural gas. The CFZ process resolves a problem with existing cryogenic distillation methods in which the formation of solid CO₂ can plug trays or packing.[68] The CFZ process adds an internal section (the CFZ) to a cryogenic distillation tower, the CFZ handling the solidification and melting of the CO₂.[69] Figs. 2 and 6, as reproduced below, illustrate a CFZ column comprising a CFZ between a lower section and an upper section.
[68] D14, page 265 column 1.
[69] Ibid.
The CFZ contains spray nozzles and a melting tray.[70] Natural gas containing CO₂ is fed into and rises from the lower section to the CFZ via the melting tray.[71] Liquid collected from the top section, within a chimney tray, spray contacts natural gas entering the CFZ.[72] Solid CO₂ forms and falls into the melting tray. Rising natural gas warms liquid forming in the melting tray and maintains it above CO₂’s freezing point.[73] All solids are confined to the CFZ and the upper and lower sections are otherwise conventional in operation.[74] Sweetened natural gas and liquid CO₂ respectively exit the upper section and lower section.[75]
[70] Ibid.
[71] Ibid, page 265 column 2.
[72] Ibid, page 265 column 2.
[73] Ibid.
[74] Ibid.
[75] Ibid.
Fig. 7 of D14 provides a flow diagram in which natural gas is chilled, fed to a first tower for condensing and separating C2 and C3-C5+ hydrocarbons, and then fed to a CFZ tower to remove CO₂. According to Table 1 of D14, the condensed liquid leaving first tower contains 2 mol% CO₂. Exxon submits this process provides the defined first cooling and separating steps.
Shell notes that natural gas is not cooled by spraying as it enters the CFZ tower. It is instead sprayed as it enters the CFZ. Shell submits that the CFZ does not constitute a “vessel”.
Exxon submits that:
“Spray cooling of the natural gas with overhead product (methane rich) liquid cools the temperature to a temperature at or below an operating temperature at which CO₂ solids form. This cooling effect commences from the point that the gas is introduced to the vessel whether or not that is characterised as the CFZ tower or CFZ zone.”
Claim 2 requires that the natural gas stream be cooled to a temperature at or below that which CO₂ solids form by spraying it with subcooled liquid as it is introduced to the cooling vessel. This does not occur as the natural gas enters the CFZ tower. The requisite cooling only occurs when the natural gas is sprayed with sub-cooled liquid in the CFZ. The lower section – where the natural gas enters the CFZ tower – operates at temperatures above that which solid CO₂ forms.
Exxon also submits that:
“The CFZ zone can be considered to be a vessel because it contains solid carbon dioxide at least until melted... A CFZ tower is a “cooling vessel” and the CFZ zone forms a section, a structural envelope’, within that tower.”
This submission is inconsistent with the evidence of Mr Tsesmelis, Dr Denton and Dr Valencia, who each describe the CFZ as a “section”,[76] “zone”[77] or “vessel space” [78] of the distillation column. The CFZ is formed by the lower melting tray and the upper chimney tray. It is in effect a distillation stage and I am not satisfied it constitutes a separate vessel within the tower. Exxon have not established that any claim lacks novelty in view of D14.
[76] Tsesmelis 1, [2.4.18].
[77] Ibid.
[78] Denton 1, [2.7]; Valencia 1, [2.7].
Inventive step
Subsection 7(2) of the Act states an invention is taken to involve an inventive step unless it would have been obvious to a person skilled in the art in the light of the common general knowledge, considered alone or together with the prior art. A document is prior art for this purpose if “a skilled person mentioned in subsection (2) could, before the priority date of the relevant claim, be reasonably expected to have ascertained, understood, regarded [the document] as relevant.”[79]
[79] The Act 1990 (Cth), s 7(3).
The relevant test for obviousness was considered by Aikin J in Wellcome Foundation Ltd v V.R. Laboratories (Aust.) Pty Ltd:[80]
"The test is whether the hypothetical addressee faced with the same problem would have taken as a matter of routine whatever steps might have led from the prior art to the invention, whether they be the steps of the inventor or not."
[80] [1981] HCA 12 at [45], 148 CLR 262 at 286.
The person skilled in the art
The person skilled in the art (“the PSA”) is the hypothetical person to whom the patent specification is addressed.[81] The identity of the PSA will vary with the nature of the invention and the field with which it is concerned.[82] In KD Kanopy Australasia Pty Ltd v InstaImage Pty Ltd,[83] Kiefel J identified the PSA as:
“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.”
[81] General Tire & Rubber Co. v Firestone Tyre & Rubber Co. Ltd (1971) 1A IPR 121, 134
[82] Aktiebolaget Hassle v Alphapharm Pty Ltd (2002) 212 CLR 411, 465 [152]-[153]; Ranbaxy Australia Pty Ltd v Warner-Lambert Co LLC (No 2) (2006) 71 IPR 46, 63[67].
[83] (2007) 71 IPR 615, 621.
Exxon identifies the PSA as a team of chemical engineers who specialise in researching and developing process designs for natural gas purification. Shell warned against misuse of the skilled team concept to cumulatively assimilate the knowledge of experts from the same field.
In Minnesota Mining & Manufacturing Co v Beiersdorf (Australia) Limited[84] Aiken J stated:
"The notion of common general knowledge itself involves 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 improvements in old, and it must be treated as being used by an individual as a general body of knowledge."
[84] (1980) 144 CLR 253, 292
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.
The problem to be solved
In determining the problem or ‘starting point’ for considering inventive step, the Full Court in AstraZeneca AB v Apotex Pty Ltd[85] stated:
“If the problem addressed by a patent specification is itself common general knowledge, or if knowledge of the problem is s 7(3) information, then such knowledge or information will be attributed to the hypothetical person skilled in the art for the purpose of assessing obviousness. But if the problem cannot be attributed to the hypothetical person skilled in the art in either of these ways then it is not permissible to attribute a knowledge of the problem on the basis of the inventor’s “starting point” such as might be gleaned from a reading of the complete specification as a whole.”
[85] [2014] FCAFC 99, [202]-[203].
Reviewing the specification and evidence I consider a relevant problem to be solved as: existing processes for treating high CO₂ content rich natural gas were not economical. I am satisfied this problem was both easily identifiable and known in the art.[86]
[86] Tsesmelis 2, [5.10].
The CGK
Physical processes for removing CO₂ from natural gas
Absorption was the most common method of removing CO₂ from natural gas.[87] During absorption sour species such as CO₂ and H₂S are preferentially absorbed into a liquid solvent.[88] Other physical processes known include use of adsorbents and membranes.[89] The separation load placed on these systems by natural gas rich in CO₂ requires high capital and operational costs, meaning development of such a reserve is “generally considered as economically unviable.”[90]
Cryogenic techniques for removing CO₂ from natural gas
[87] Tsesmelis 1, [2.4.2].
[88] Ibid, [2.4.5]
[89] Dugan 1, [3.12].
[90] The specification, page 1 line 34 to page 2 line 6.
Cryogenic techniques referred to in evidence include bulk fractionation, Ryan Holmes processing, CFZ processing, and “Cool Energy” processing.
Bulk fractionation comprises passing dehydrated natural gas into a fractionation column from which methane rich gas and CO₂ rich liquid are separated.[91] The process is called bulk fractionation because, although the bulk of the CO₂ may be removed, a substantial portion will remain in the methane rich gas.[92] When cryogenically separating CO₂ from methane solid CO₂ will form when the CO₂ content reaches a certain point.[93] As this causes blockages within the tower, compositions nearing this point are avoided. To remove further CO₂ a further removal stage is required.[94] Further removal stages specifically identified in prior art documents include absorption technology,[95] or a second fractionation column operated under lower pressure conditions.[96] US 5983663, as described in the specification, relates to a bulk fractionation process.
[91] Tsesmelis 1, [2.4.11].
[92] Ibid, [2.4.12].
[93] Tsesmelis 2, [6.25], [6.26].
[94] Tsesmelis 1, [2.4.12(a)].
[95] Tsesmelis 1, [2.4.12(a)]; Jarrett, F., “Fundamentals of Acid Gas Fractionation,” Hydrocarbon Processing,
[96] Tsesmelis 1, [2.4.13]; Schianni, G., “Cryogenic Removal of Carbon Dioxide from Natural Gas”, Institution of Chemical Engineers Symposium Series, 44 (1976) 50.
The Ryan Holmes and CFZ processes each modify bulk fractionation to overcome CO₂ solidification issues and thus allow for greater removal of CO₂ within the column. In Ryan Holmes processing a suitable solvent is added to a fractionation column to prevent CO₂ solidification.[97] CFZ processing, as I noted above, handles CO₂ solidification within the CFZ of the fractionation column.[98]
[97] Dugan 1, [3.16].
[98] Ibid, [3.17].
Mr Tsesmelis declared that he considers the Cool Energy separation techniques (“Cool Energy”), by which I refer to the research of Professor Robert Amin conducted through Cool Energy Ltd, to be known.[99] This technology is exemplified by D4. Mr Tsesmelis considered that Professor Amin’s reputation in the industry meant his research became common general knowledge upon its publication in documents such as D4.[100] However Mr Tsesmelis appears to have misunderstood that “a document can be considered to be common general knowledge in Australia if the document could reasonably be ascertained, understood and regarded as relevant to natural gas purification by a skilled person.”[101] As such it is not clear what he knew and considered to be known about Cool Energy, and what he misunderstood to be “CGK” more simply because it is disclosed in D4. The two are not the same. Mr Tsesmelis also notes he was informed by Exxon of a licensing agreement between Shell and Cool Energy, which he takes as indicating a degree of assurance on Shell’s part about the feasibility of the technology.[102] There is no evidence that he, or those in the industry generally, knew of the licensing agreement to infer anything of the technology’s feasibility at the priority date.
[99] Tsesmelis 1, [2.4.30].
[100] Ibid, [2.4.26].
[101] Tsesmelis 1, [2.4.31]; see also Tsesmelis 3, [11.16].
[102] Tsesmelis 1, [2.4.29].

While Mr Dugan accepted that Professor Amin is a well-respected academic in petroleum engineering circles,[103] he declared:
“The most one could say about Cool Energy Ltd’s activities was that it was conducting trials of cryogenic separation and removal of carbon dioxide as solids but the details about the process and associated technology were not known or understood on or before February 2007.”[104]
[103] Dugan 1, [7.4].
[104] Ibid, [7.5].
I accept that the PSA by reputation broadly knew of Cool Energy Ltd’s research into separating CO₂ by solidification.
Conservative nature of the industry
Both Mr Tsesmelis and Mr Dugan acknowledge the conservative nature of the industry.[105] Mr Dugan states:
“I work within a very conservative industry which seeks to minimize its technical risk… In particular, given the very significant costs with the development of technologies in this industry, it is standard practice to seek to rely on 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.
In respect of a problem in the field of removal of acid contaminants from natural gas containing ethane and C3+ hydrocarbons, I would have confined my enquiries to technical solutions involving chemical or physical solvents, and possible separation membranes.”[106]
[105] Tsesmelis 1, [2.1.2]; Dugan 1, [3.2.4].
[106] Dugan 1, [3.2.4].
This passage alludes to cryogenic technologies having been researched and trialled while not having been applied commercially.[107] I accept that when designing and commissioning an LNG plant the PSA would prefer “tried and true solutions”. However the present problem identifies that physical processes are not economical at high CO₂ content. I am not sure Mr Dugan directed himself to this specific problem. If he did then his steadfast reliance on physical processes is interesting given he was involved in Cool Energy Ltd’s cryogenic research before the priority date.[108] There is a difference between considering how one might uninventively solve a problem and refusing to consider a problem. I am satisfied that the PSA would research emerging technologies such as cryogenic technologies in view of an identified problem with established technologies.[109]
[107] Ibid, [6.13].
[108] Dugan 1, [2.8].
[109] Tsesmelis 3, [11.10].
What would the PSA, in view of the CGK, have done as a matter of routine?
Exxon submits that the PSA would, as a matter of routine, have tried combining bulk fractionation with either CFZ processing, or Cool Energy, and thereby arrive at the invention. In this arrangement the bulk fractionation process would provide the defined first cooling and separation stages while the CFZ or Cool Energy processes would provide the second cooling vessel.
As an initial point I do not agree with Shell’s submission that bulk fractionation was understood to teach away from any separate polishing step that involved freezing the CO₂. Bulk fractionation teaches against solidifying CO₂ because it causes blockages within the fractionation tower.[110] This does not give the PSA any reason to avoid subsequent polishing steps designed to handle CO₂ solidification in a separate vessel. What occurs downstream will not affect what occurs upstream.
[110] Tsesmelis 2, [6.25], [6.26].
I already found that the CFZ process does not provide the second cooling vessel as defined. In addition the CFZ process is designed to overcome the limitations of bulk fractionation such that natural gas can be sweetened in a single tower.[111] In other words, it is designed as “an alternative to bulk fractionation”,[112] and not a means of complementing it. I am not satisfied it would be a matter of routine to supplement a bulk fractionation tower with subsequent CFZ processing where one is seeking to reduce costs.
[111] D14, 265.
[112] Denton 1, [2.11]; Valencia 1, [2.11].
I discussed above what I am satisfied was known about Cool Energy. The PSA knew that Cool Energy Ltd was conducting trials into cryogenic separation and removal of CO₂ as solids. It is not otherwise clear what of Cool Energy was widely known. Mr Tsesmelis submitted that the contents of D4 were known, however he appeared to misunderstand the test for CGK.[113] Exxon has not established that the PSA knew:
·     how Cool Energy works with any specificity;
·     what processing conditions Cool Energy was bested suited to, and in particular that is was thermodynamically limited to treating natural gas with a CO₂ content of less than 15-25%; and/or
·     whether Cool Energy was established as a potentially economic alternative for removing CO₂ under certain conditions.
[113] Ibid, [2.4.31].
In summary I am satisfied that the PSA would have looked to cryogenic technologies to solve the identified problem. There are several options in this area that PSA would have considered, including: bulk fractionation and subsequent polishing; Ryan-Holmes and CFZ processing. Cool Energy was known of at a broader reputational level, however I am not satisfied more specific details regarding its relative technical and economic merits were widely understood. I am not satisfied it would have been a matter of routine to supplement bulk fractionation with a subsequent Cool Energy CO₂ removal step.
The prior art
Exxon rely on the following as s 7(3) prior art:
D3 US 5819555 A (ENGDAHL) 13 October 1998;
D4WO2004/070297 A1 (Shell Internationale Research Maatschappij B.V.) 17 August 2004;
D5Jarett, F.W., “Fundamentals of Acid Gas Fractionation” Hydrocarbon Processing (April 1983), 67; and
D14Haut, R., et al., “Development and Application of the Controlled-Freeze-Zone Process” SPE Production Engineering (1989) 265.
Ascertainability of the prior art
This is not the first opposition proceeding between the current parties in the present technology. In ExxonMobil Upstream Research Company v Shell Internationale Research Maatschappij B.V.[114] the delegate stated:
“There is competing evidence as to whether persons in this art considered patent literature (in Tsesmelis 3, Northrop, Dugan 1). On balance, it seems likely that a person would consult databases that cover both patent and non-patent information, and D1 could have been ascertained. On its face, D1 is clearly relevant to removal of sour species from gas.”
[114] [2014] APO 51, [60].
I similarly have competing evidence from Mr Tsesmelis[115] and Mr Dugan.[116] I am similarly satisfied that: the PSA would consult databases that cover both patent and non-patent literature; that D3, D4, D5 and D14 are relevant to removal of sour species from gas; and that I could reasonably expect those documents to have been ascertained.
D3
[115] Tsesmelis 1, [2.1.3].
[116] Dugan 1, [6.16].
D3 discloses a process similar to that of Cool Energy in which natural gas is expanded through a valve into a vessel where solids are formed in the presence of vapour and liquid.[117] The vapour stream containing the sweetened natural gas is separated from the liquid and solids and the solids are melted to provide a liquid stream containing CO₂.[118] In the disclosed example a stream containing 5% CO₂ is sweetened to 1.1% CO₂.
[117] D3, column 5 lines 8-46 and claim 1.
[118] Ibid, claim 1.
Exxon submits that D3 discloses a process that is equivalent to the second stage process defined in the specification. It submits that the disclosed unit operation would be readily used to supplement known bulk fractionation processing without modification. However I am not convinced. Listed among the objects of D3 are:
“To provide the separation without the use of distillation, and the expense, energy use, and complication of a cryogenic distillation system.”[119]
and
“To provide a process which can achieve start-up without the investment of additional separation apparatus.”[120]
[119] Ibid, column 3 lines 61-63.
[120] Ibid, column 3 lines 66 and 67.
D3 therefore appears to teach away from the invention. Exxon have not established that any claim lacks an inventive step in view of D3.
D4
Exxon submits that, if D4 does not anticipate process claims 1-5, 8, 9, 11, 12 and 19, then it would be a matter of routine to select conditions in which CO₂ would condense in the second flash tank 40 as this would reduce CO₂ concentrations to acceptable levels that could be processed by the disclosed Cool Energy process.
I have two primary concerns with this submission:
· it presumes that the PSA knew of the thermodynamic limitations of Cool Energy (to treating 15-25% CO₂), which Exxon has not established; and
· D4 does not clearly teach that the condensate from the second flash tank 40 should be removed from the system. The condensate may instead be used as either: a sub-cooled liquid for the first vessel 12[121] and/or the second vessel 14,[122] and/or as a means to melt solid CO₂ in the second vessel 14.[123] In other words, it is recycled through the system such that I am not sure condensing CO₂ in the second vessel 40 would prevent it ending up in the second cooling vessel 14 and affecting the thermodynamics of the process.
I am not convinced the PSA would, reading D4 in its entirety, readily identify any need for an initial CO₂ removal stage or identify the second vessel 40 as a suitable CO₂ removal stage.
[121] D4, page 7 lines 18-26.
[122] Ibid, page 10 line 29 to page 11 line 3.
[123] Ibid, page 11 lines 5-11.
When discussing novelty I stated I consider it possible, depending on processing conditions, to separate a liquid stream of CO₂, ethane and C3+ hydrocarbons in the second flash tank 40. It may be that in implementing the teaching of D4 against a certain natural gas feedstream the PSA would as a matter of routine have chosen processing conditions in which the defined liquid stream would inherently result. This has not been established by evidence.
Exxon have not established that any process claim lacks an inventive step in view of D4.
Regarding the apparatus claims I am satisfied that, having ascertained D4, it would have been a matter of routine to implement the disclosed apparatus while seeking to solve the identified problem. Claims 13-16 lack an inventive step in view of D4. Regarding claims 17 and 18, I accept that gas-liquid contact means such as packing or stages were well a known in the art for increasing mass transfer.[124] I also accept that absorption processes typically involve such gas-liquid contactors.[125] This does not however establish that it would be a routine step to provide such packing or stages to the second vessel 14. The second vessel is not described as an adsorption vessel. The evidence demonstrates that solidification of CO₂ would clog packing and trays (unless the trays have been specifically designed such as with the CFZ).[126] Regarding claim 19, for reasons I have set out above, I am not satisfied it would be a matter of routine to add a bulk fractionator (as disclosed in the specification) to the system of D4.
D5
[124] Dugan 1, [6.32], [6.33].
[125] Tsesmelis 3, [10.87].
[126] See for example D14.
D5 provides an explanation and review of bulk fractionation. Exxon submits that it would be routine to combine bulk fractionation with the CFZ process or Cool Energy and thereby arrive at the invention claimed. As I discussed in relation to the CGK alone I am not satisfied this is the case. Exxon have not established that any claim lacks an inventive step in view of D5.
D14
D14 discloses the CFZ process. I am not satisfied leading the PSA toward the CFZ process would result in the invention claimed. Exxon have not established that any claim lacks an inventive step in view of D14.
Conclusion
The opposition succeeds on the grounds that claims 13-16 lack novelty and an inventive step. As these grounds can be overcome by amendment, I will allow Shell an opportunity to amend.
Costs
Exxon has been successful in its opposition. Generally costs should follow the event. The present case is complicated by Exxon having introduced D14 as a particular for novelty two weeks before the hearing date. Exxon performed a similar action in ExxonMobil Upstream Research Company v Shell Internationale Research Maatschappij B.V.[127] which the delegate looked upon unfavourably when awarding costs. While I am similarly dissatisfied by Exxon’s preparation of its case, the present opposition’s success did not turn on the introduction. As such I am satisfied that costs should follow the event and that Exxon should be awarded costs.
[127] [2014] APO 51, [72]-[76].
Rhys Munzel
Delegate of the Commissioner of Patents

(April 1983) 67.