.J c PTC:.s - {):.J. - 03 Development and Transmission to Market of British Columbia NatlUral Gas Reserves

By PETER R. KUTNEY'· and A.LTON T. TYLER*

(A.nullal Westen"t llIeetiny, C.l,J11., l'ancol/ver, OctobcT,1964)

ABSTRACT In 1950 and 1951, intensified drilling in the Dawson

The discoHry of huge natural gas reserves in British Creek area resulted in gas shows in the Cadotte for­Downloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021 Columbia, strategically located with respect to almost un­ mation at a depth of approximately :3,200 feet, and in limited markets for this premium fuel along the entire the Upper Triassic rocks at a depth of -I,800 feet. Pacific Coast and in the Far East, has led to the rapid A number of gas wells were completed, but, due to deYelopment of the \Vestcoast Transmission Company's pipeline sJstem during the period from 1957 to date_ De­ their limited producing capacity, were nevcl' connected li\'eries of gas, present!}- in the magnitude of 500 million to market. cubic feet per daJ" in the wintertime, are expected to in­ crease to the Yicinit:r of a billion cubic feet per day in All this exploration was a forerunner to the estab­ the next similar period as a result of recent reserve devel­ lishment of a :-;ufficient ~upply of gas fOl' the pm­ opments in the Fort Nelson area and the anticipated con­ po~ed \Vestcoast Tran~mission Company pipeline, al­ tinual growth of markets in Canada and the 'Vestern ready conceived in the mind of Frank M_ McMahon. States, and off-shore shipments of LMG as far as Japan_ To bring these large l'olumes of gas to market, \Vestcoast Based on the commercial qLlantitie~ of reserves found presentll operates 1,000 miles of gathering lines and 30­ adjacent to the British Columbia bonier in Alberta in. mainline_ This is being expanded this lear by a ~57,­ and his knowledge that the sedimentary basin in 000,000 construction program into the Fort Nelson area close to the border of the Northwest Territories. '''''hich these reserves were found extended over into northeastern British Columbia, Mr. i\'1cMahon relent­ A re,-iew of the development of natural gas resen'es in the Fort St. John and Northwestern Alberta fields has lessly pursued his dream of building a big-inch pipe­ been followed by similar material cOl'ering the new Fort line to supply natural gas to the lower mainllllul of Nelson area. British Columbia and the Pacifie Northwest states The transmi.ssion of British Columbia gas resen"E.'S to of the United States. market requires a complex pipeline s}'stem involving the handling of gas Crom the "arious fields, both sweet and Pacific Petroleums LteL, one of the spolU~orillg com­ ~our. wet and dry, at hi~h and low pressures, all under an panies of \Vestcoast, esblblished the first commercial extreme range of weather conditions_ Briefl}' described production of natural gas in British Columbia by the are the Company's wellhead dehydration and gathering systems, treating plants, measurement stations, compres­ discovery of the Fort St_ .John field in UJ52. This dis­ sor stations and mainline facilities_ covery was made as a result of combining :H1rface geology ,... ith l:;;ub-surface information disclosed by r HISTORY OF DEVELOPMENT two dn holes drilled on a surface structure_ This was followed by further discoveries during 1952. and this HE first exploration for petroleum substances in year marked the beginning of active exploration in T northeastern British Columbia was initiated by northeastern British Columbia. From a total of tell the Provincial Government during 1921 and 1922 when exploratory wildcat well~ drilled during the year 1952, six shallow wells were drilled north of Hudson Hope. the number has steadily increased to a total of sev­ These well~, drilled to depths of between 1,000 and enty-two wildcat wells drilled during the year 1963, 2,500 feet, wel'e unsucce~sful. During the period ulltil the Federal Power Com­ No further activity took place until 1940, \vhen the mission's approval to import gas into the United Provincial Government drilled a 6.940-foot test ap­ States was obtained. on November 25, 1955, dl'illing proximately 70 miles west of Dawson Greek. The \vell efforts were directed tm\-al'd proving up as much gus wa~ abandoned with no shows_ re~erves as possible with the least number of wells. In 19-18, the firl:it apparent commercial discovery of In other words, the discoveri es were follo\'red up by gas in British Columbia was made adjacent to the widely spaced step-out welI~_ Alberta border near Pouce Coupe. The first well to After all authorizations were finally received by be completed as a potential gas producer was Peace \Vestcoast on November 25, 1955, development drill­ River Natural Gas No.1 [since renamed '~lestcoast ing \\'ent into high gear to provide the necessary de­ POllee Coupe 6-30-80-13 (1)]. This well \vas actually Jiverability. \Vhen \\'estcoa.!'!t went on stream in late an exten1::iion to gas pl'oduction already discovered on 1957, it was drawing on gas from fifty-two gas wells the Alberta ~ide_ The producing capacity of this well in eight fields (two of which were single-well field.!'!) was only in the neighbourhood of 500 thousand cubic in British Columbia anci thirty gas wells in three feet per day. and hence this well ' ...·as never placed on ficlds in the Peace River area of Alberta. The total production. established gas reserves in British Columbia, at thllt time, were between 1.5 and 2.0 trillion cubic feet. In addition, \Vestcoast had a permit from the Alberta Oil --""Manager of Gas Supply and Sales; -:"="'"Ma1!agcl' and Gas Conservation Board to export approximately of Operati01/s and Engineering; H'estcoast T1'ans1nis­ 1 trillion cubic feet from reserves established in the sion Company Limited, YanCO'llV6T, B.C. Peace River area of Alberta.

62 The Journal of Canadian Petroleum ,. Downloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021

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o • , .. LEGEND '. G.AS RESERVE FtIRT St JOHN ~ fORT NELSON ­ EXISTING GAS PIPELINE9 WESTCOAST - OTHERS ---'-'

---Figure 1._Present and Pl-oposed Su:pply Areas. 63

Technology, April-June, 1965, Montreal During the first heating season of its operation tions, have been found within i\oliddle Devonian car­ (1957-1958), \Vestcoast was delivering gas to its bonates, usually the Slave Point formation_ The gas markets at maximum rates of approximately 275 mil­ accumulations occur in :Middle Devonian barrier reefs lion cubic feet per day. This has increased to approxi­ which have grown on the edge of a shale embuJrmenL mately 500 million cubic feet per day during the past Dolomitization of a narruw band of limestone reef has heating season_ given good vuggy and intercr.rstalline POl'OHity. The \Vestcoast In-esently gathers gas from approximate­ reef front is generally pOrOlLg dolomite or dolomitic ly 250 ga~ wells located in twenty-two gas fields in limestone which grade~ into dense limestones in the northea~tern British Columbia (Ftgltl'e 1). The pres­ backreef areas. It dips ver)" ~teepl)r into the shale ent supply area covers an area of approximately 10,­ basin, 000 square miles, extending from the Da,..·son Creek Seismic methods hm'e been very ~ucce~~flll in de­ field in the southeast to the North Jedney field in the lineating the reef fronts in this area. Sub.:'iequent drill­ Ilorthwe~t. ga~ i~ The gathered, exclusive of pruducer ing along these honts has led to the discovery of the line~, gathering through some 408 miles of gathering Clal'ke Lake, Kotcho Lake ~lnd Petitot River fields, as \Ve~tcuast system. In addition, gather13 gas from ap­ well as numerous undeveloped ~ingie-well areas. The proximately thirty-three ga::; wells in six gas field!=; in results of certain ~ei::imic dahl which were made avail­ the Peace Rive1' area of Alberta. able for our inspectiun indicate an apparentl,v cuntill­ The total number of ga~ wells in B1'itish Columbia 1l0LIoS major reef front extending from ~outhwest of now ~tands at approximateI,}" 480, a sharp increa~e CI£lrke lake in a meandering path east to the JuniorDownloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021 from the 15 at the end of 1952. field, and trending northward through the ICotcho, Cabin and Petitot River fields toward Celibeta lake, GeoloY!J a Lotal distance of approximately 285 miles_ Drilling The area under discussiOll (northeastern British Co­ and other minor sei.-;mic cOlltrol indicates the pres­ ence of reefs to the ea.-;t alld west. pal"illlel to the lumbia) represent..; a portion of the \Vestern Cal1a­ maj01' reef front_ diall Sedimentary Basin, consisting of a wedge of .sediments which thickens from 7,000-8,000 feet along The Triassic beds, which are the m,lin gas resel'­ the Alberta - British Columbia border to over 14,000 \-oirs to the south, are entire.ly missing due tu sedi­ feet along the mountain front west of Fort St. John. mentary thinning and erosiun. Cretaceou.-; sediment~, The thick .sequence of sediments, made up of Devon­ consisting of shales and .sandstones, lie directly 011 top ian, Mississippian, Permo-Pennsylvania, Triassic. of the eroded Mis:"iissippian surface_ J ura~sic: and Cretaceou~, thin or "wedge out" hom wes.t to ea!::it. The majority of the hydrocarbon ac­ DC'/leloplJlent rli Resel'l:~'.'i ill the Fort Nl'1.'irm Area cumulations fuund thu~ far are associated with local :structural entrapment. There have been a total of In :May of 195G, the first indication of gas-bcllring fourteen horizon~ that have been established as pro­ Nliddle Devonian (Slave Point) reefs in thc area was ducti\'e of ga~, ranging from the Cadutte member of established by the drilling of Shell Gulf [(lua Creek the Lower CretaceoLls to the Slave Point formatiun #a-50-C (I-A), about 24 miles southea~t of thc Fu,·t of the Middle Devonian. Nel::ion townsite. The well te~ted 8,000 to 12,000 Mcf per day on a driIl-.-;tem test, and was left suspended The deposition of sediments in the southern part of because of the remote po~sibilit)r of a market outlet. thi::; area wa~ most influenc.ed by the tectonic feature known a~ the Peace River Arch_ This arc-h, caused by In the winter of 1956-57. \Vestern Natural Gas Com­ an uplift of the Precambrian basement rocks, pro­ pany Inc. (now acquired by Pacific Petroleum~ Ltd.) truded above sea level throughout much of the Paleo­ began an aggressive program of exploration fur l\'lid­ zoic: Era. Progressi\-e onlap of sediments e\-entually dIe Devonian gas with the drilling of the Prophet cm-ered the an::h by late Upper Devonian time, Dur­ River No.1 well (now known £1:-: \Ve,!;t Nat ct al. Clarke ing :Mississippian to Permian time, the arch collapsed #c:.-47-J). This well wm; drilled on the western edge along the faults which had originally given rise to it. of what has now been defiTled as the Clarke Lakc The block-faulted sUl-face contained many deep field. During the following winters, a total uf thir­ troughs or grabens into which later IVIississippianJ teen wells were drilled in an attempt to define the Penn~yh'anian and PermiHll sediments were dumped, reserves as::iociated with thi~ particular accumulation Probably the most important sediments in the south­ (Clarke Lake). These wells were drilled Oil a wide d~­ ern are"l of northeastern British Columbia are of spacing pattern, as it was recognized early in the Triassic age. The thickness of the Triassic val'ies velopment of the field that, because of the high de­ from zero at the pinch-out edge (nurth-northeast of liverability characteristics of the~e wells, conventional the J edney - Laprise Creek area) to 3,500 feet in the spacing patterns were of secondary importance, Nine vicinity of Moberly lake. The thinning to north and of these wells have been completed as g'a~ wells. Of northeast is due both to depositional thinning and the seven which Hre tested and ready for production, to erosion at the end of Triassic time_ Folding of the Absolute Open Flows range from 12,000 Md/D In these sediments in the J edney - Laprise Creek area 1:3.5,000 Met/D, with an t\\'erage of (iO,OOO McflD. was a re.::5ult of the Laramide Orogen~r - the action In the winter of 1958-59. \Vestel'n Natural discu\'­ whic.h resulted in the build-up of the Rocky i\:loun­ ered the Kotcho Lake and Petitot River fields_ The tain:;. The folding gave rise to long N.N\V_- to S.SE.­ discovery well in Rotcho Lake (V{e.-;t Nat Kotcho Lal~e trellding ~tructUl-eH, which are now the majol- source #c-67-Kl ha~ established an Ab~olule Open Flow po­ of gas in that area. The three productive resen'oirs tential of 825,000 Mcf/ D. There have been a total of of the Triassic Im\'e to date contributed approximate­ six gas wells completed in the Kotcho Lake ficld. The ly 70 per cent of the proved reserves in \Ve::itcoast's discovery well in the Petitot River field has estub­ present supply area. li~hed an Absolute Open Flow potential of 153,000 In the Fort Nelson area, all reserves of gas, with IVlcf/D. There have been a total of four gas well~ the exception of some minor Mississippian accumula- completed in the Petitot River field.

64 The Journal of Canodian Petroleum ~. :.- 1

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EXISTN;; CDM~SSCRSTATIQM ""c ...

EXISTING NllINUNE - EXISTIIlG ca.1HEAJNG SYSTEM - - PRDFOSEO CONiTRUCTIOH

MAJOR PIPELINES S. GATHERING SYSTEMS

Figu?"e 2. ~ ." .' ",;-~.>

Technology, April-June, 1965, Manfreal 65 In the \vinter of 1961-62, Middle Devonian (Slave The original '\Vestcoast system was completed and Point) production was established at Yoyo. The dis­ put into service in 1957. It consisted of 646 miles of covery well, \Vest Nat et al. Yoyo a-74-H, established 3D-in. mainline extending from the McMahon plant an Absolute Open Flow potential of 185,000 iIIlcf/ D. at Taylor, near Fort St. John, to Vancouver. ReI·e, The offsetting wells, having found the Slave Point in addition to serving the southwest portion of the dense, penetrated deeper and established commercial Province, it ties into the northern terminus of the productiun in tbe Elk Point. The tested Elk Point Pacific Northwest Division of the EI Paso Natural wells have Absolute Open Flow potentials ranging up Gas Company system. The mainline was powered by to 146,000 iIIlcflD. A total of five wells have been five compressor stations totaling 54,020 hp. completed in the Yoyo field - one in the Slave Point The system, designed initially for a capacity of ,150 and four in the Elk Point. million cubic feet per day, was fed from the sweet As of this date. there has been a total of thirty­ and sour gas fields in the Fort St. John area through eight rdiddle De\'onian gas wells completed in the Fort more than 100 miles of gathering line ranging in size Nelson area of British Columbia. Of the said thirty­ from 4 to 26 inches in diameter. This gathering sys­ eight \\'ells, twent)r-seven have been completed on the tem has been extended in the Fort St. John area to "major" reef front las hereinbefore described) trend­ include more than 413 miles of pipeline and three ing from Clarke Lake to Celibeta_ booster stations totaling 10,620 hp. In 1963, the capacity of the 30-in. mainline was RESERVES Downloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021 increased to 500 million cubic feet pel' day by the ad­ From the nominal 2 trillion cubic feet of recover­ dition of Compressor Station No.2, neal' Chetwynd, able re!':ierves which were established just prior to the B.C.• totaling 8.000 IIp. date on which the 'Vestcoast gas pipeline went into A major expansion of the sy~tem wa~ undertalcen service, the reserves in northeastern British Colum­ in 1964. This extends the mainline another 220 miles bia have increased to an estimated 6.8 trillion cubic from Mainline Station No, 2 to the Fort Nelson area, feet. Of this total, slightly more than 0.5 trillion have This 3D-in. line, together \.... ith additional gathering been produced to date, leaving a remaining recover­ lines and treating plant facilitie::;, will, for the first able resen'e of 6.:3 trillion cubic feet. These, by the time, tap the huge gas reserves surrounding Fort way. are conservative estimates, and are considerably Nelson. lower than the estimate of reserves as calculated by the Provincial Department of .Mines & Petroleum Re­ To handle the Fort Nelson gas, the capacity of the source~. present 3D-in, mainline is being increased to G70 mil­ Of the 6.8 trillion cubic feet, reserves of approxi­ lion cubic feet per daJ~ by the addition of five com­ mately :11 trillion cubic feet have been established pressor stations totaling 46,000 hp. in the Fort Nelson area. A. summary of \Vestcoast facilitie::; is given in The 6.3 trillion cubic feet, coupled with the 900 bil­ Tables I and II. lion cubic feet available to ,"VestcoaRt from the Peace River area of Alberta, makes a total supply, available to 'Vestcoa~t, of 7,2 trillion cubic feet. At vVestcoast's 19G,'=\ rate of ::iHles, there moe sufficient presently es­ T.\BLI: I tablished resen'es to last approximatel,}' 53 years. To WESTCOAST TRANSMISSION COMPANY LIMITED put it in other words, '\Vestcoast could double its SUl\-1MARY OF PIPELINE l\llLEAGE 19G:3 sales and still have available to it a 25-year sup­ ply. Trml.wrissjon Gatlrerjng To/at ACclwllIla/jlfl: '\Vestcoast ha~ also maintained continuing studies Year Lines Lines J\filwf,1' Talal uf the trendf; in the exploration for and the growth of ------natural gas reserves in northeastern British Columbia. 1957 ... 683.22 116.70 799.92 799.92 1958 .. - 89.88 89.88 889.80 These stUdies, based on fourteen years' history, indi­ 1959 .. - 39.29 3929 ~)29.09 cate H discernible trend in the growth of initial dis­ 1960. - 78.80 78.80 1007.89 posable gas over the period from 1957 to 1963 at a 1961.. - 50.01 50.01 1057.90 1962 .. - rate of approximately 800 billion cubic feet of 30.91 30.91 1088.81 1963 .. - - - 1088.81 "proved" reseL"VeS pel' ye.ar. 1964 .. 220.90 15.70 2::16.60 1325.ol1 It i.s believed that it can be safely predicted that ------T(ltals .. 904.12 421.29 1325.41 this average growth rate will continue as a minimum for a number of years. If this growth rate \vere main­ tained for, say, the next ten years, the "new'! reserves to be added to the area due to the appreciation of DESIGN AND OPERATION presentl,}r known gas reserves and new' discoveL"ies would total 8,000 billion cubic feet - for a total The entire '\Vesh~oast system has been designed in "proved" initial disposable reserve of approximately accordance with ASA B3L8 Code requirements. How­ 14 trillion cubic feet hy the end of 1973. eyer, government and industry are presently engaged, on a national basis, in drafting Canadian codes for both gas and oil pipelines. Gathering system pressureB FACILITIES nu";)! from 200 to 1,200 psig, and the mainline design (F'igUJ'e 2) operating pressure is 936 psig.

To transport the British Columbia gas reserves to FORT ST. JOHN GATHERING SYSTEM market, \Vestcoast operates a $300,000,000 pipeline system in which natural gas, both wet and dry, s'veet The B.C. Gathering System essentially handles ~oUl' and sour, in many cases v"ith hvo-phase flow, is han­ gas which is wet with both water and hydrocarbon li­ dled under an extreme range of climatic conditions. quids, and thus \...·as designed for two-phase flow. Two-

66 The Journal of Conodian Petroleum ,'. .

.TABLE II WESTCOAST TRANSMISSION COMPANY LIMITED-COMPRESSOR HORSEPOWER SUMMARY

MAINLINE STATIONS Total Compressor Station ll-lilepost No. of Units Year Horsepower 1...... Taylor 0.0 6 Ingersoll-Rand 1957 2,000 hp. Recip. . .. 1 Ingersoll-Rand 1961 14,000 2,000 hp. Recip. 2...... -..... Willow Flats 76.3 4 Ingersoll-Rand 1963 8,000 2,000 hp. Recip. 2B..... _ .. - · . Azouzetta Lake 112.6 - - - - 3 ...... McLeod Lake 149.4 4 Nordberg-DeLaval 1957 15,280 3,820 hp. Cent. 4A ..... - ... .. " Summit Lake 205.3 1 Westinghouse-DeLaval 1964 9,200 9,200 hp. Cent. 4 ...... Prince George 232.4 - - - - 4B.. .. _ ..... ·. Hixon 261.3 1 Westinghollse-DeLavaL 1964 9,200 ,~\:- 3,200 hp. Cent.

5... - ...... Australian 317.7 4 Nordberg-DeLaval 1957 15,280 ·~l.~.~··,,-Downloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021 3,820 hp. Cent. 6A.. .. _ .. - - --. 150 IvIile House 367.9 1 Westinghouse-DeLaval 1964 9,200 9,200 HP. Cent. 6 .. .. . -- ... . Lac La Hache 397.9 - - - - 6B...... · . 93 Mile House 419.6 1 Westinghouse·DeLavaL 1964 9,200 ~$~? 9,200 hp. Cent. ': I 7... -- -- _ .... - Savona 482.3 3 Nordberg-DeLaval 1957 ~t-·- .\ 3,820 hp. Cent. , 1 Nordberg-DeLaval 1962 15,280 3,820 hp. Cent. 8A.. .. - _ .. - ... Kingsvale 539.3 1 Westinghouse-DeLava! 1954 9,200 9,200 hp. Cent. Total Horsepower .. _.•. .. 113,840 '. BOOSTER ST,ITIONS 1 - _._- .. .. '" Taylor - 2 Ingersoll-Rand 1960 660 hp. Recip. 2 Clarke 1961 2,640 ;. 660 hp. Recip. , , 2 .. - _ ..... ·. Bonanza -- - - - 3... _.- ...... Kobes - 3 Ingersoll-Rand 1961 6,000 2,000 hp. Recip. 4 ...... -- ..... Buick - 2 Ingersoll-Rand 1960 660 hp. Recip. 1 Ingersoll-Rand 660 hp. Recip. 1961 1,980 Total Horsepower...... 10,620

phase flaw indicates a gaseous phase and a liquid 3.-An increase in the gas flow rate would bring on phase flowing simultaneously in a pipeline. Pressure higher than normal amounts of liquid into the 1\[0­ .drops, for two-phase flaw lines, are higher than Mahon plant at TaJ'lor. normally experienced in single-phase lines for several 4_-Stabilized two-phase liquid lines have been known j'­ l'easons: to unload their liquid and bring large uncontrolled i liqUid slugs down to the plant. I.-The gas-phase flow in the pipe has less area avail­ As our primary purpose in laying the lines to the able to it because of the liquid. Therefore, the ve­ field was to get gas to the gas plant and to the main­ locity of the gas is increased and the pressure line continuously, the interruptions that can occur drop. in the gas phase, is also increased. with the liquid slugging problems were not de­ 2.-Wetting of the interior pipe wall, bj' the liquid sirable. We were then faced with the other alter­ phase. increases the roughness of the pipe wall native of not allowing the lines to stabilize. and this and increases the pressure drop in the gas phase. was accomplished by pigging them frequently. Pig­ 2_-Energy is required to be expended' by the gas in ging the two-phase lines also incurred some problems. lifting the liquid flow over each rise or hill, and The pigging had to be done fl'equently enough "to this is reflected in an additional pressure drop. bring in a volume of liquid to the plant that could be Our experience with two':'phase flow in large-diam­ comfortably handled by the inlet scrubbers and stabil­ ..tel' lines (18, 20 and 26 in.) has been quite inter­ izers. Liquid slugs, larger than this amount, required ..sting. To let the two-phase lines build up and stabil­ a line shutdown until the liquid was removed and ize would mean that we would have: normal line operation restored_ During the - initial year of operation, the 26-in. Alaska Highway Trunk 1.-Extremely high pressure drops at the initial low Line was pigged twice dail}~. To increase operating flow rates_ flexibility, it was decided that some other metbod be 2.-A very large volume of liquid held· up in the line. developed to handle the liquid so that the plant could

Technology, April-June, 1965, Montreal 67 receive and handle it at a controlled rate while main­ &~S II COllOElI5.l.TE GI,S II CONDElI ....I[ taining continuous gas flow. In 1958, 6,200 feet of 1110" IIELO 'L -" ,10 PRocEU --PL'''T. 20-in. b~r-pass line was laid upstream of the Taylor plant. This allowed the accumulation of liquid in the ~- 26-in. line while by-passing the gas from behind the \ pig to the plant, The liqllid could then be fed from - fLI the storage loop into the plant scrubbers at a con­ I trolled rate. This solved our immediate problem. and is working yery well even at the higher flow rates - we are experiencing today. It has allowed us to de­ 1fII b JI crease oUr pigging frequency, and has increased our 1,--=<=51j I liquid recovery. L ~OU~RESSOII H;OIION [(I"PR[HO'l 'UTlOH \Vith regard to proteding our gathering sY:item 5UCTIO,. 011 CII"II~[ from the effects of sour wet gas, it was decided to Pigw·c .'l_-LilJllid hUlIdling (OT(II1 gl'JH ('1/( /If rhe I\ob("~ start off immediately with an inhibitor (Kontoll in­ Creek bool,;fl'l" statinl/. jection program. All of the lines were precoated with a mixture of diesel nil and inhibitor prior to being placed in sour gas service. Corrosion coupons and hy­ den:iing out of the condensate in the pipeline. Some uf resaturate~ drogen probes \vere installed at the origin and ter­ this water contacts the gas phase and Downloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021 il. minus of each gathering line. and the inhibitor was The excess wateL' will gather in the pipeline sags, ThiH injected continuously at the sending barrel of each makes frequent pigging of our gathering lines neces­ lateral. Obtaining low-pressure pm\'er gas. to run in­ sary to remove accumulated water from the :-lags hibitur injection pump!'; at each of these locations, re­ (Figure .']). quired the installation of a heated regulator station Since 1957, the SOUr gag gathering ~ystem has been with fluid knock-out~. It was decided to go to this extended by 285 miles of pipeline. \Vith the exlension method through an empirical approach. The indi"idual of these line~ many miles farther north than we had installations ~lre expensive. but once in and operating anticipated initially, the installation of compressor they have done an excellent job. horsepo,,'er became neces.<::arJ·. The l:ompressioll of sweet gas is quite conventional, and the compression Initially, the hydrogen probe presSllres were checked of dry SOUl' gas l:Cln be accomplished readily. but the daily and coupons removed and examined once a instailation of compressors on a two-phase system that month. \Vith the continued !:'uccess of our injection program, we now read the hydrogen probe and pl'es­ is pigged frequentb' imp0:-les some rathel' ullusual HIres twice weekly and check the coupons every six problems. At i\Iilepogt Sl2 on the Alaslca Highw

68 The Journal of Canadian PetrOleum . ;..:.... -, ~ ~~:\~C ,._-- '. '1 r: ,- ,;.• The engine shutdown functions at this station are ferential. The 6-in. pressuring line valve is then t ! , ~. ·1 qUite normal - opened. Vilhen the isolated section of the lS-in. line ;::'. ; is brought up to station discharge pressure, the kicker ,- 1. Low oil pressure 2. High oil temIlerature valve on the l8-in. receiving scraper barrel is opened 3_ High jacket water temperature and the fluid is discharged into the 20-in. Alaska ,;, 4. Low jacket water pressure HighwaJr line. The pig is brought into the scraper 5. High discharge gas pressure barrel and the valve sequence is reversed, bringing 6. ·Low suction gas pressure 7. High compressor cylinder temperature the flow to the station suction back through the 8. High liquid level in the suction sCl'ubbel-S normal piping. It normally takes 60 to 90 minutes to bring in a pig~ With reliable pig signals, the system There is also a remote shutdown function that can has worked extremely well. In order to prevent loss be initiated from the Fort St. John dispatch office. of natural gas condensates coming into the station One further item of interest at this station is the op­ when no pig is run, the liquids from the inlet scrub­ .'. eration of the gas condensate blow-cases. \Vhen the bers are dumped into one of the two large blow-cases liquid level in the inlet scrubber builds up to a pre­ and discharged into the 20-in. Alaska Highwalr line determined level, a magnatrol sends a signal to the with hot discharge gas. blow-case controls. The blow-case then automatically The station at Kobes Creek is manned eight hours vents to 5 lbs. below suction pressure and this allows Downloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021 easy passage of the liquids from the inlet scrubber to per day, seven days per week. The station complement the blow-case. At the Kobes station, \ve ha,re two blow­ includes a foreman, who spends approximately half of his time at another field booster station, a station op­ cases that are controlled by a timing sequence. 'Vhen , c one blow-case is filling, the other blow-case can be erator, an assistant operator and an electrical utility , discharging to the 20-in. Alaska Highway line. Should man. This normally leaves two men on dayshift. All conditions require, we then have a continuous filling fOUl" of the station personnel live on site. This semi­ , " and dumping process. The inlet scrubbers at the sta­ attended operation of the Kobes Creek station has tion have two additional liquid level controllers at a been possible because of the use of a limited supervis­ :...... : level higher than the blow-case fill line. The inter­ orJ' s}'stem that functions over our V_H.F_ radio fa '- mediate liquid level controller actuates the station the Fort St. John dispatch office. The dispatcher, by dump line to the flare pit and the upper level con­ dialling the proper three-digit coding sequence, can troller is the high-liquid-level alarm that shuts down request a suction or discharge pressure from the com­ all compressor units_ pressor station and a differential reading from each .' of the suction lines coming into the station. l\iinor or The operation of the gas by-pass line, when a pig major alarms are telemetered from the station to the is arriving, is of some interest (Figure 8 and 5). Fort St..John dispatch office. The dispatcher can also Under normal operation, the gas flow comes through shut down the compressor station from Fort St. John. the IS-in. full-opening gate valve at the start of the The station must be started and brought back on the loop, into the station suction and out the station dis­ line manually. charge line_ When a pig, pushing a load of fluid ahead of it, comes into the loop it trips a pig signal down­ The natural gas h:irdrates and two-phase flow have stream of the 18-in. gate valve, which then starts to caused us some problems in gas measurement_ 'Ve close. At the same time, a plug valve on the loop blr­ have had occurrences when our men were removing a pass line, at the compressor station, opens; and the pig from one of the receiving scraper barrels and have plug valve, on the normal suction line, closes_ In this found buckled orifice plates or straightening vanes manner, the pig, with its liquid slug, is isolated in the ahead of the pig. The removal of this primary equip­ loop. The station is taking suction on the 18-in. line ment by the gas hydrates creates a certain number of behind the pig. The main station discharge valve is problems with gas measurement. It is not uncommon, pinched closed to create a higher pressure on the on orificate plate inspection at a deliver}' point, to station side of the valve than there is downstream in find gas hydrates formed on the inner surface of the the 20-in. pipeline. ,~re normally require a 40-lb. dif- orifice plate. This, in effect, decreases the diameter of the orifice and gives the meter a higher than normal differential reading, resulting in faulty meas­ urement_ vVith high de\\'point gas there has also been -~------,,

1.-. .-.-. i" .., L-_.- Figlll-e 5.-A receiving semper ba1Te.l on the 18-in. Alaska L Highway line at the Kobes Creek boosteT station. Figm·B G.-A receiving ba?"l"el on the 1fZ-in. Rigel line.

Technology, April-June, 1965, Montreal 69 a tendenc)' for the lead lines between the orifice flange and the meter to freeze off, requiring esti­ mates of production. Normally, measuring two-phase flow through an orifice meter will give you a 1-2 per cent enol' on the high side. Another typical field bom.:;ter station used to com­ press the wet sour gas in the eastern leg of the gath­ ering system is the Buick Creek station. A scraper barrel installation on a typical wet sour gas lateral (the 12-in. Rigel field line) is shown in Figure 6. As the bulk of our gathering operation is concerned Figw'e ?-Fivc amine crmtacton! and stills at the with the transport of sour ga~, safety and safe opera­ McMahon plant, Taylol·, B.C. tion become fundamental. ,"Vestcoast management has made a vet·,r concerted effort to make available the necessary safety equipment to ensure the safety of their employees. Safety meeti ngs are held monthly at Downloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021 each station. plant and pipeline location. It i~ the re­ sponsibility of ~lll superintendent.s and foremen to think and act "Safety." To carry out this program. \"'eRtcoast has adopted the following practices: L-Demonstrations in the use of all safety equipment. including the pneolator, ::;elf-contained air breath­ ing equipment, fire extinguisheL's, etc.. are held. 2.-Monthly safety meetings are conducted 011 Com- pany time. 3_-A safety check routine fOl' all \"ehides wor!(ing in the Fort St. John area has been e.stablished. 4.-First aid courses are made available tu employees at Company expense. Figu)"!' 5_-Thc steam plant at TayIOl·, B.C. It has a 5.-Hard hats, ear protectors and gas-tight safety cal)Ucit!/ of (ion,non lb.'!. PC?" !rOlrl'. goggles are made available ,lnd used at hazardous locationR. 6.-Safet~· glasses are il:iSlled to all employees. 7.-i.\'Iouth to mouth resuscitation equipment and first aid kits are installed in all field vehicles. S.-All Company units that are required to go into the field are equipped with two-way radios. The McMahon plant is situated on the north bank of the Peace river at Taylor. B.C. (Mile­ post 36 on the Alaska Highway). The gas trellting plant (Plant 'A') was placed on .::itl'eam in November. 1957. The condensate treating plant (Plant 'B') was started up in February, 1958. and a small crude uil rc­ fi nery (Plant 'C') \nl.::i completed and put into opern­ tion in 1960. The gases coming into the l\'IclVli.lhon plant from the Fort St. John and Alaska Highway fields contain approximately 2 per cent H::S and 2 pel' cent CO:!, natural gas condensate and some \'Imter. The Mc:i\'1ahon plant consists basically of seven large inlel scrubbers to separate the two-phase liquid, five sep­ arate amine trains to s\...·eeten the gas (Fiunrc 7), natural gas absorbers to Rtrip the heavier hydrocar­ bons out of the gas stream and foul' Silica-Gel dehy­ drators. The plant produces its own electL'icit.y and stearn requirements (Figu1"e S). The electrical pow­ er output is 7.500 k.v.a" and the cooling water pumps can sLlpply 35,000 g.p.m. The plant capacity is in ex­ cess of 350 I\'IMcf/D of pipeline gas, and 3,000 bar­ rels of pentanes plus are prodLlced daily. The acid gase~ from the amine stills of the Mc­ Mahon plant are taken over to the Jefferson Lake sul­ phur treating plant (Figure 9 J. The gas is then burned in the reactor furnaces and the sulphur re­ moved. The sulphur plant is designed for 300 long Figa1"C ,9.-The .Tejferson Lake slll1Jlmr plant. tons per day.

70 The Journal of Canadian Petroleum The Alberta Gathering System handles sweet gas r------.------...----. -.. ----- (also wet witlt some ,vater and smaller amounts of j i liquid hydrocarbons) that has heen produced in sweet l gas fields or treated for H~S l".emoval at plants in­ . ~ stalled in sour gas fields (FigU1"e 10) _ This sweet ., ;, gas also goes into Compressor Station No.1, at Tay­ lor, B.C. (Figu're 11). Here it is compressed and min­ gled with sweet gas from the McMahon plant. The clean, dry hlend of the two gases then enters the 3D-in. mainline for transport to market.

FORT NELSON SYSTEM Initiall)', the Fod Nelson system will handle gas from the Clarke Lake field only. As the market re­ quirements increase, the gathering system will be extended to tie into other fields in the area. The raw sour gas from the Clarke Lake field will Figlo'c 10.-The ;ield amine t1'eating plant at Bounda11J be transmitted 8 miles through a 16-in.-O.D. x 0.250­ Lake, B.C. It has a ca,paeity of 10,000,000 en. jt./D. in.-'\V.T. pipeline to a gas processing plant located 15 Downloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021 miles south of Fort Nelson, B.C., adjacent to the Alaska Highwa)' at ~rilepost 285. The plant will have two separate trains operating independentl}r and each having a design capacity of 100 MMscf/D of raw gas...... The initial capacit~r will allow the processing of 200 MMscf/D of raw gas, which, after removal of acid gas : ::: components and provisions for plant fuel, will result in 170 lVIlIIscf/D of net pipeline gas. The gas will be sweetened using the Hot Potassium Carbonate Treat­ ing Process, followed by the Monoethanolamine Treat­ ing Process to remove the hydrogen sulphide down to sales gas specifications. The sweet gas will be deh}r­ drated by passing it through towers containing solid ~ .. desiccant. From the Fort Nelson gas processing plant, the gas ,vill be delivered to the present 3D-in. mainline at ".. Station 2 near Chetwynd, B.C., through the 220-mile, Figw'e 11.-Compressor Station No.1 at the 11IcilIahon 3D-in. Fort Nelson extension. Initially, no compres­ plant, Taylo1', B.C. sion will be required on the Fort Nelson extension.

l\'lAlNLJNE HORSEPOWER stopping the unit. Fault alarm indication will be transmitted to the remote controlling station, in con­ Five new compressor stations are being constructed junction with station suction and discharge pres­ on the present 3D-in. mainline to handle the addition­ sures, and turbine speed. al Fort Nelson gas. The compressor stations will each consist of a West­ STATION AND UNIT CONTROL SYSTEMS inghouse \V92 model industrial, non-regenerative c}rcle, two-shaft combustible gas turbine, rated at 9,200 hp., A. Engine Conb'ol Panel and P'}'otective Devices each drh'ing a DeLaval single-stage centrifugal com­ Each unit is equipped ,vith the following protec­ pressor with horizontally in line 3D-in. suction and tive devices supplied b.y the turbine-compressor manu­ dis.charge_ facturers: The compressor stations will each consist of a com­ L Station battery - low charge rate pressor building, control building and auxiliary build­ 2_ iLC. power failure (over 2 minutes) ing. The compressor building ,vill initally contain one 3. High station discharge pressure turbine and compressor, and associated lube and seal -1. High station discharge temperature oil systems, ·with provision for fu.ture extension to in­ 5. Low control air supply pressure 6. Incomplete starting sequence corporate a second turbine-compressor. 7. Combustor discharge overtemperature The control building will contain the station and B. Low axial compressor suction pressure unit control panels, and communications equipment_ 9. TUl'bine-compressor bearings, case or lube-coolant overtemperature The auxiliary building will contain the generators 10. Turbine-compressor or cooler fan excessive vibration and switchboard, motor control center, emergency gen­ n. Turbine overspeed 12. Combustor outfire erator, station batteries, hot water boiler and com­ 13. Turbine or gas compressor lube oil pl'essure low pressed air systeln_ 14. Low fuel gas pressure 15. Low gas compressor seal oil differential pressure 16_ Lube oil reserl'oir low level OPERATION 17. Clutch malfunction The stations are designed for semi-unattended op­ 18. Turning gear malfunction. eration. The units will be self-protected and fail-safe, The above devices ,,,,'ill shutdown and blowdown the and arranged for local start with prOVIsion for re­ unit and present visual and audible alarms to both motel)' changing the discharge pressure set point or the local and master stations.

Technology. April':June. 1965. Montreal 71 In addition, the following result in shutdown: gas supply during station shutdown except in event of fire or gas detection in the auxiliar.'l building. 1. Fire detection :2.. Gas detection The emergenc}r shutdo'...·n system can be aetivllted 3. Emergency push-button activation at three locations in the hazardous area and at three -:1. Low station discharge pl'essure locations out of the hazardous area. The following functions present visual and audible The compressor station is planned to be operated a,s alarms to both local and master stations: an automatic sbltion, with unattended operation ex­ 1. Low station suction pressure cept for a one-man da",' shift. All alarms and shut­ 2. Low starting gas Tll'essure downs will be announced locally and transmitted tu ::.:. Gas detector malfunction the master station. 4. Fire detector malfunction 5. Station batter).' high charge rate 6. Boiler malfunction CONCLUSION 7. Generator malfunction 8. Supervisory battery alarm The \Ve~tcoast 1964 expansion program. including $l. A.C. power failure (under 2 minutes) 10. Gas compres.sor seal oil filter high differential pres­ the Fort Nelson extension. i1; nearing completion and sure will soon be placed in gas service. 11. Air filtel' runout This is expected to be a forerunner to fUl'ther ex­ pansion that will see the capacity of the ~ystem dou­ B. Sfafi()/I Panel a}ld Protcctil'e Devices bled in the next few years to deliver British CulumbiuDownloaded from http://onepetro.org/JCPT/article-pdf/4/02/62/2166013/petsoc-65-02-03.pdf by guest on 28 September 2021 The t:.ompres~or station will be protected from over­ natural ga;:; to the growing markets in British Colum­ pressure by a relief valve in the discharge piping bia and the \Vestern State.:', with possible uff-shore which will also blowdown the station piping when the shipments of LMG as far as .Japan. emergency shutdown system is activated. The emer­ gency shutdown system will also cause motor-operated BIBLIOGRAPHY three-way valves to close the station suction and dis­ charge valves and open the station by-pass valve. It AllYJlC and Stewart, "Constnlctin~ and 0pcl'UtiuJ.!,'" Gn8 Gathering and Transmission Systems in the Far will also transfer th~ station to the emergellc~' fuel North," May 4, 1964.

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EADERS of. The Journal of Ca,'nadian Petro~eUln r:echnology are reminde? that reprints of H1rls( R of the techmcal papers that have been pllbhshed In these pages are avallable from the Journul Business office. The price is fifty cents each to the membership of The Canadian Institute of Mining and 'Metallurgy and one dollar each to non-members.

72 The Journal of Canadian Petroleum