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QR코드 사용안내 스마트폰 사용자는 QR코드 응용 프로그램(어플리케이션)을 다운받아 설치하여 실행하면 <>을 스마트폰으로도 보실 수 있습니다. 서울 중구 남대문로 5가 537 GS역전타워 Tel: 82-2-728-1114 Homepage: http://www.gsconst.co.kr 2013 vol. 07 OFFSHORE

은 글로벌 기술 동향, 건설 경제와 문화, 그리고 GS건설의 기술을 소개하는 기술 매거진으로서, CONTENTS 목차 건설인들의 활발한 정보 교환 및 의사 소통의 場 을 지향하고 있습니다. 2013 vol. 07 특히 글로벌 기술 동향은 Special Theme로 비중 있게 다루어 건설인들이 글로벌 전문가들과 정보를 교환할 수 있도록 노력하겠습니다. 이번 2013 vol.07 에서는 OFFSHORE 를 Special Theme로 선정하여 최신 기술 트렌드를 조망해 보았습니다. 004 인사말 CTO 전무 서정우 006 Special Theme : OFFSHORE 해양 석유개발의 역사와 기술발전 최종근 서울대학교 에너지자원공학과 / 교수 The Trend of Offshore Technology 유선일 DNV Korea / Senior Customer Service Manager 해양플랜트의 위험도기반설계 (Risk-Based Design for Offshore Installations) 108 Technology in Practice 인도네시아 Cilacap RFCC 프로젝트 콘크리트 내구성 설계 류종현 재료에너지연구팀 선임연구원 베트남 TBO도로 - 빈로이교(닐센아치교) 시공 사례 민만경 해외CM팀 부장 (공동 저자 : 김봉준ㅣ토목구조팀 과장) KNPC NLTF 프로젝트 지진하중해석 서원석 지반팀 차장 Fire Risk Assessment for Performance Based Design - AEON mall in Cambodia 박준 건축환경연구팀 전임연구원 장대준 한국과학기술원 해양시스템공학과 / 부교수 Analysis and Design of Offshore Structures Subjected to Extreme Environmental Loads and Accidental Actions Jørgen Amdahl Norwegian University of Science and Technology / Professor 144 New Technology 해양구조물용 고내구성 경량콘크리트 기술 손명수 재료에너지연구팀 선임연구원 자이아파트 사운드스케이프 디자인의 적용 방안 070 Project Panorama 이상준 건축환경연구팀 선임연구원 하이브리드 바이오가스화 기술 발행인 임병용 편집인 서정우 편집위원 박종헌, 이선근, 조재영 발행일 2013년 10월 15일 (년 1회 刊 ) 발행처 GS건설(주) 소재지 서울시 중구 남대문로 5가 537 GS역전타워 홈페이지 www.gsconst.co.kr 제작 (주)피플웍스프로모션, (주)커뮤니케이션신화 문의 GS건설(주) 기술기획팀 김혜연 대리 T. 02-728-3527 E-Mail. hykim9@gsconst.co.kr < >은 한국 간행물 윤리위원회의 윤리강령과 실천요강을 준수합니다. < >에 실린 글과 사진은 저작권법에 의해 보호를 받습니다. < >은 GS건설에서 발행하는 매거진입니다. GS건설(주)에서는 독자의 고견을 기다리고 있습니다. 목포대교 메세나폴리스 부곡3호기 LNG복합화력발전소 건설공사 (충남) Ruwais 4th NGL Train Project 078 Biz Trend 해양 관련 미래 기술 연구 동향 엄항섭 대우조선해양 중앙연구소 / 소장 How an EPC Company can enter the Offshore Market Tom Haylock KANFA Group Offshore EPCI 시장 진입을 위해 E&C 회사가 나아가야 할 방향 임문채 플랜트OFFSHORE팀 / 위원 이동열 환경연구팀 선임연구원 고함수율 폐기물 선별을 위한 최적 MBT 프로세스 개발 정경미 환경연구팀 선임연구원 158 Culture 홈가드닝으로 힐링 하라 가든하다 라이프스타일 크리에이터 로마에서 최고의 휴일을 경험하다 서울을 바라보는 새로운 시선, Sketch in SEOUL 이장희 작가 / 일러스트레이터함께 자란다 김재중 한국문화예술위원회 차장 2012 여수세계박람회, 세계를 둘러보고 미래를 경험하다 생활비 거품 쏙 빼는 경제 다이어트 GS건설(주) 기술기획팀으로 연락 주시면 본지의 발전을 위하여 적극 반영할 예정이오니 많은 관심 바랍니다. < >에 게재된 원고 내용은 GS건설(주)의 의견과 다를 수 있습니다.

인사말 안녕하십니까? 유난히도 장마와 무더위가 기승을 부렸던 여름도 다 지나고 파란 하늘이 무척 청명해 보이는 가을을 맞고 있습니다. 올 한해는 무엇보다도 에너지의 중요성에 대하여 다시 한 번 느낄 수 있었던 해로 기억이 됩니다. 많은 분들과 건설 산업의 현재와 미래 발전을 함께 생각하는 기회를 만들고자 시작한 < >이 벌써 발간 5주년을 맞이하였습니다. 그 동안 창간호에서의 Green Construction 을 시작으로 Smart Construction, Environment, Energy, Innovative Infrastructure, Cost Saving Technology 에 이르기까지 그때그때의 기술적, 사회적 현안들을 Special Theme로 다루어 왔습니다. 이번 < > 제7호에서는 이미 시장의 많은 부분을 국내가 아닌 해외에서 찾아야 하고 육상이 아닌 해양으로까지 그 GS건설은 기술개발, < >발간, 기술세미나 개최 등을 통해 건설 분야 선진 기술 동향을 끊임없이 공유하고, 교류하는 노력을 통해 건설 산업 발전에 기여하겠습니다. 사업의 범위를 넓혀 가야 하는 건설 산업이 당면한 도전적 과제를 함께 고민해 보고자 해양에서의 건설 산업을 조망한 OFFSHORE 를 Special Theme로 선정하였습니다. 그 외에 현장의 원가 절감 및 문제 해결을 위한 기술 적용 사례와 설계 및 시공 VE 사례를 살펴보고, 자체 개발한 신기술 등을 소개하였습니다. 이러한 사례들이 참고가 되어 국내외 많은 건설 현장에서 더욱 큰 성과로 확대되기를 기대해 봅니다. 끝으로 건설 산업은 물론이고 건설인들 모두가 이 어려운 시기를 슬기롭게 극복할 수 있기를 바라면서, GS건설 기술지 < >에 대한 독자 여러분의 지속적인 관심과 격려를 부탁드립니다. 감사합니다. CTO 전무 서정우

Special Theme OFFSHORE 08 14 해양 석유개발의 역사와 기술발전 The Trend of Offshore Technology 50 해양플랜트의 위험도기반설계 (Risk-Based Design for Offshore Installations) 56 Analysis and Design of Offshore Structures Subjected to Extreme Environmental Loads and Accidental Actions

l Special Theme l OFFSHORE 최 종 근 교수 서울대학교 에너지자원공학과 I. 석유의 역사 현대인은 석유와 함께 일어나고 석유와 함께 생활하다 석유와 함께 잠든다! 는 말이 나올 정도로 석유는 우리의 일상생활과 경제활동에 필수적이다. 석유( 石 油 )의 어원은 그리스어로 암석을 의미하는 Petro 와 기름을 의미하는 oleum 의 합성어이다. 보통 원유(crude oil)를 석유로 인식하는 경우도 있지만 이는 아주 좁은 의미이다. 석유란 자연발생적으로 존재하는 탄화수소의 혼합물로 정의되며 온도, 압력, 조성에 따라 액체, 기체, 반고체의 상을 가진다. 혼합물이란 탄소와 수소의 결합으로 구성된 각 탄화수소분자들이 화학적으로 결합하지 않고 단순히 섞여 있음을 의미한다. 따라서 석유는 액체인 원유, 기체인 천연가스, 반고체 상태인 역청 그리고 응축물과 같은 수반물을 모두 포함한다. 다양한 기록에 의하면 석유는 기원전 수천 년 전부터 사용되어 왔다. 초기에는 자연적으로 노상에 침출된 유징을 이용하여 석유를 발견하였다. 부식 방지를 목적으로 목재 및 배의 코팅에 역청을 사용하거나 일부 의약품으로 이용하였다. 그 후 19세기 초반까지 석유의 이용이나 탐사기술에 대한 현저한 변화나 발전은 없었다. 해양 석유개발의 역사와 기술발전 19세기 중반에 들어서면서 교육이 증가하고 신문과 잡지 같은 읽을거리가 보급되기 시작하였다. 너무나 당연한 이야기이지만 밤에 신문이나 잡지를 읽기 위해서는 불빛 이 필요했다. 불빛을 효과적으로 제공하기 위한 재료는 적정가격, 효율적인 조명, 깨끗한 연소 등과 같은 조건을 만족시켜야 했다. 정제되지 않았던 원유는 심한 매연으로 인하여 널리 사용되지 않았지만 처음 두 조건은 너무나 잘 만족시켰으므로 정제의 필요성이 인식되고 정제기술 또한 조금씩 발전하기 시작하였다. 미국에서 산업혁명과 시민전쟁을 거치면서 대규모의 석유 수요가 생겼고 노상천에서 채취되는 석유만으로는 수요를 충당하기에 부족하여 석유탐사가 필요하게 되었다. 지금은 너무나 당연히 여기지만 그 당시로는 기념비적인 생각, 즉 땅속을 시추하면 많은 양의 석유를 찾아낼 수 있다는 생각을 한 사람이 Edwin Drake이다. 탄성파탐사와 같은 과학적인 기술이 없었던 당시로는 노상천 주위를 무작위로 시추하여 그의 이론을 증명할 수밖에 없었다. 수많은 시행착오와 파산의 경제적 난관을 이기고 펜실베니아 Titusville에서 그는 지하 21m에서 석유층을 발견하였다. 이때가 1859년 8월 27일이며 근대 석유산업의 출발일로 인식되어 있다. 증가하는 석유 수요와 높은 수익으로 인하여 석유산업은 큰 전기를 맞았다. 특히 텍사스 주 Spindletop 유전의 발견(1901년 1월)은 시추액과 가솔린 동력을 사용한 회전식 시추기법의 최초의 상업적 성공이라는 점에서 큰 의미를 가진다. 이 유전으로 인하여 걸프(Gulf Oil)와 텍사코(Texaco: 초기 회사명은 Texas Fuel Company)를 비롯하여 100여 개 석유관련 회사가 설립되었다. 록펠러가 1870년 1월에 설립한 Standard Oil 회사도 사업의 절정기에는 미국 내 판매시장의 90%를 독점하였지만, 독과점방지법에 의하여 Exxon, Mobil, Chevron 등 여러 개의 회사들로 분리되었다. 석유의 탐사와 개발은 여러 분야의 공학기술이 집약된 종합적인 기술과 폭넓은 경험을 요구한다. 따라서 1970년대까지도 석유의 탐사와 개발, 공급은 자본력과 기술력 그리고 경험을 갖춘 7 Sisters 라 불린 거대 석유회사들(Exxon, Mobil, Chevron, Texaco, Gulf Oil, Royal Dutch Shell, British Petroleum)에 의해 좌우되었다. 대표적인 산유국인 중동국가들과 남미국가들은 자국의 자원에 대한 권리와 이익을 챙기지 못했고 이들 메이저회사들로부터 원유가격의 약 10% 내외의 조광료와 세금을 받는데 만족해야 했다. 1950년대가 지나면서 7 Sisters 로 대표되던 메이저회사 외에도 중소 독립석유회사들이 등장하고 석유자원을 보유한 나라의 자각과 더불어 산유국의 기술력도 점차 향상되었다. 이런 움직임은 1960년 9월 주요 산유국(Saudi Arabia, Kuwait, Iraq, Iran, Venezuela)의 석유수출국기구(OPEC) 결성으로 이어졌다. 이들은 당시 세계 원유수출의 80% 이상을 차지하였다. OPEC의 결성은 회원국의 유가와 석유정책을 통일함으로써 생산국, 소비국, 투자자 모두에게 공정하고 안정된 상호이익을 추구한다 는 원론적인 목적을 가지고 있었으나, 실제로는 메이저석유회사에 대항해 산유국의 이익을 보호하는데 주목적이 있었다. 또한 자원민족주의를 지향하여 자국의 자원을 국유화하였다. 1973년 10월의 중동전쟁과 1978년 10월 이란의 회교혁명으로 인한 석유파동으로 자원보유국의 위상은 더 강화되었다. 1980년대 이후부터 2000년도 초반까지의 유가는 배럴당 30달러 이하의 저유가였다. 국제정치적 또는 계절적 요인으로 유가가 일시적으로 급등하는 경우도 있었지만 다시 안정화되는 양상을 보였다. 하지만 2000년대 후반기부터는 고유가를 유지하다가 산유국의 문제뿐만 아니라 글로벌 경제의 영향으로 유가가 급등락하는 현상을 나타낸다. 또한 석유자원의 개발에 따른 환경규제와 기업의 책임이 매우 강화되고 있다. 따라서 급변하는 국제정세 속에서 석유자원을 안정적으로 확보하는 것이 지속가능한 사회를 위해 무엇보다도 중요해지고 있다. II. 육상시추의 역사 시추가 이용되는 분야는 석유자원의 탐사와 개발, 광물자원탐사, 지하수개발, 토목시공 등 매우 다양하다. 시추는 목표심도에 따라 천부시추와 심부시추로 나눌 수 있으며 시추목적에 따른 분류도 가능하다. 하지만 석유의 탐사와 개발을 위한 시추를 제외한 대부분의 시추는 수십에서 최대 수백 미터의 천부시추이다. 008 009

토목시공과 관련된 시추는 수십 미터 이내의 전형적인 천부시추로 시료채취, 지반조사, 깊은 기초, 연약지반 개량 등을 위해 사용된다. 석유를 탐사하고 생산하는 상류부분에서 시추는 물리탐사를 통하여 파악된 유망구조를 직접 확인하고 불확실성을 줄여준다. 따라서 향후 대규모의 투자를 필요로 하는 개발단계로의 진행 여부를 결정하게 도와준다. 또한 생산을 위한 생산정 또는 물이나 가스를 주입하기 위한 주입정을 시추하여 효율적인 석유생산 활동을 가능하게 한다. 이와 같이 중요한 시추는 긴 현장적용 역사를 통하여 현대적인 기술로 발전하였다. 시추의 필요성에 의해 시추장비를 개발하고 현장 작업에 적용하였다. 하지만 초기에는 예상하지 못했던 다양한 시추문제들이 발생하였고 이들을 해결하고 시추심도를 증가시키는 과정에서 많은 기술과 안전한 절차들이 개발되었다. 이와 같은 과정이 시추의 역사이며 지금 이 시간에도 안전하고 경제적인 시추를 위한 노력이 계속되고 있다. 지하에 뚫린 오래된 구멍을 보면 인류는 오래 전부터 사냥, 마실 물, 소금광맥 등을 찾는 과정에서 시추를 수행하였음을 알 수 있다. 농경사회의 발전에 따라 관개용수나 지하수 개발을 위한 시추도 이루어졌지만 1800년대까지는 지하수나 석유의 개발에 대한 필요성이 상대적으로 적었다. 산업혁명이 일어나기 전까지 인력이나 동물의 힘을 이용한 도구가 대부분이었기 때문에 의미 있는 시추장비의 발전도 없었고 시추심도도 얕았다. 1859년에 펜실베니아에서 Edwin Drake가 시추기술자 William Smith와 함께 시추를 통한 최초의 상업적 인 유전개발에 성공했는데, 이 때 사용한 시추리그가 케이블툴리그(cable tool rig)이다. 이 리그는 시추탑 (derrick), 권양시스템, 동력원인 엔진, 시추비트, 장비의 이동에 필요한 케이블과 도르래 등으로 구성된다. 케이블 끝에 매달린 시추비트를 일정한 높이로 들어 올린 후 낙하시켜 그 충격으로 지층을 파쇄하며 굴진이 이루어진다. 하지만 하루 평균 굴진율이 수 미터 내외로 [그림1] 로터리 시추리그의 모식도 (최종근, 2012) 낮고 지하수나 원유가 시추공으로 유입되면 이들의 관 리와 제어가 쉽지 않은 단점이 있다. 또한 굴진작업과 암 편 제거 과정을 교대로 반복해야 하는 한계가 있어 로터 리 시추리그가 보편화되기 전까지 많이 사용되었다. 케이블툴리그의 한계를 극복하고 굴진율을 증가시키기 위해 1860년대 후반부터 시추비트를 회전시키는 로터 리 시추리그(rotary drilling rig)가 사용되었다. [그림1]은 육상 시추리그의 모습을 보여준다. 로터리 시 추리그를 사용하면서 부드러운 지층이나 깊은 심도의 목표층도 시추가 가능해졌다. 비트의 회전력과 시추파 이프의 무게로 인한 압축력을 동시에 이용하므로 시추 속도가 급격히 증가하였으며 이수(mud)를 사용함으로 써 굴진작업과 동시에 암편을 제거할 수 있게 되었다. 또 한 이수를 사용하여 시추공의 압력을 조절하므로 시추공의 안정성도 향상되어 시추할 수 있는 심도가 깊어 졌다. 육상시추의 발전은 해양시추기술의 발전과 더불어 현재 수직 깊이 10km 또는 수평거리 10km 이상까지도 시추가 가능하다. 최근에는 고온과 고압을 나타내는 지층을 안전하게 시추하기 위한 장비와 기술의 개발이 이루어지고 있다. [표1]은 석유개발과 연관된 시추 기록이다. 2013년 5월말 기준으로 수직 깊이로 가장 깊게 시추된 시추공은 미국 멕시코만의 Tiber well로 10,683m(2009년)이다. 측정 깊이로 가장 긴 시추공은 러시아 Sakhalin의 Odoptu OP-11 well로 12,345m(2011년)이다. [표1] 시추 관련 세계기록 Type Well name Length, ft Year Operator Location Comments Bertha Rogers#1-27 31,441 1974 GHK Oklahoma Dry hole Knotty Head 34,194 2005 Chevron GOM By Drillship Measured depth Z-12 38,322 2008 Exxon Neftegas Ltd Sakhalin Island Extended reach well BD-04A 40,320 2008 Maersk Oil Qatar Offshore Qatar Extended reach well Odoptu OP-11 40,502 2011 Exxon Neftegas Ltd Sakhalin Island Extended reach well Vertical depth Blackbeard 32,550 2008 McMoRan Exploration GOM Tiber 35,050 2009 BP GOM AC-813 8,070 2002 Shell GOM By Semi-Rig L-399 8,951 2004 Shell GOM Water depth Trident 9,727 2001 Unocal GOM By Drillship Toledo 10,011 2003 ChevronTexaco GOM NA7-1 10,385 2013 Oil and Gas Corp. Offshore India III. 해양시추의 역사 석유자원을 탐사하고 생산하기 위한 업계의 노력이 계속됨에 따라 그 대상지역이 육상 및 천해지역뿐만 아니라 극지와 초심해 지역까지 확장되고 있다. 해양 시추리그의 모태는 제2차 세계대전 전후로 개발된 보급선에 시추탑과 필요한 장비를 탑재한 것이었다. 해양시추의 역사는 석유자원의 탐사와 생산을 위한 시추가 가능한 수심의 한계를 극복한 과정이라 할 수 있다. [표2]는 이동이 가능한 시추리그의 작업수심에 따른 세대별 분류를 보여준다. [표3]은 1940년대부터 발전하기 시작한 해양시추의 역사를 대표적인 업적과 기술을 중심으로 요약한 것이다. 1940년대 중반 이후부터 1960년대 이전의 시기는 해양유전개발의 태동기라 할 수 있다. 미국에서는 개인이 육상 사유지의 광구권을 소유하지만 주정부와 연방정부가 대륙붕과 심해의 광구권을 각각 소유한다. 1945년에 루이지애나에서 처음으로 해양광구에 대한 광구권 판매가 이루어졌다. 처음에는 해상에 플랫폼을 건설하는 어려움으로 인해 1960년대 말까지 작업수심의 한계는 60m 내외였다. 1960년 이후 20년간은 해양유전의 시추와 개발을 위한 기술들이 본격적으로 연구되어 많은 발전이 이루어 졌다. 1961년에는 시추선의 위치를 동적으로 제어하는 동적위치선정시스템(DPS)과 해저 방폭장치(subsea BOP)가 개발 되었다. 또한 원격운영장치인 ROV(Remotely Operated Vehicle)가 개발되어 Shell에서 해 010 011

[표2] 해양 시추리그의 세대별 분류 Generation Water depth, ft Dates First 600 Early 1960 s Second 1,000 Early 1970 s Third 1,500 Early 1980 s Fourth 3,000 Mostly 1990 s Fifth 7,500 After 1998 Sixth 10,000 After 2005 Seventh 12,000 After 2010 [표3] 해양시추의 중요 사례 및 기술 Year Key events and technology Louisiana holds first offshore lease sale (1945) 1940 s First use of tender platform support (1947) First offshore submersible barge (1949) Texas holds first offshore lease sale (1953) 1950 s Platform installation depth reaches 100 ft (1955) Jackup installation depth reaches 200 ft (1959) Use of dynamic positioning (1961) 1960 s Development of subsea BOP (1961) Fixed platform depth reached 200 ft (1962) Offshore Technology Conference (OTC) starts (1968) Drilling water depth hits 2,150 ft (1974) 1970 s First floating production system begins work (1975) Shell s Cognac Platform installed in 1,022 ft water depth (1978) First artificial drilling island built off Alaska (1982) Production water depth exceeds 2,000 ft (1984) 1980 s Drilling water depth reaches 7,512 ft (1988) Bullwinkle, deepest fixed platform installed at water depth 1,353 ft (1988) J-lay pipeline laying operation (1993) 1990 s Auger TLP installed at water depth 2,860 ft (1994) Production exceeds 5,000 ft water depth (1997) Water depth record of 10,011 ft by Drillship, Discoverer Deep Seas (2003) Water depth record of 8,951 ft by Semi-submersible, Nautilus (2004) 2000 + WTI price hits $147.27/bbl (July 11, 2008) WTI price hits $30.28/bbl (Dec. 23, 2008) Water depth record of 10,385 ft by Drillship, Dhirubhai Deepwater KG1 (2013) 저작업에 활용하였다(1962년). 해양유전의 탐사와 개발을 위한 기술과 경험을 나누기 위하여 OTC(Offshore Technology Conference)가 1968년 처음 시작되었고 지금도 매년 5월초에 미국 Houston에서 개최된다. 1970년대에 두 번의 오일위기를 겪으면서 석유자원의 중요성 이 모두에게 각인되었다. 따라서 안정적인 석유자원의 공급을 위하여 중동지역을 벗어나 다른 지역의 해양유전을 개발하기 위 한 많은 시추가 이루어졌다. 1974년에는 당 시 최대 시추수심 655m를 달성하였고 1977 년에는 지중해에서 Shell이 저장탱크를 최 초로 이용하여 원유를 생산하였다. 국내에서 도 석유자원의 탐사와 개발 그리고 비축을 위해 1979년 3월 한국석유개발공사(현 석유 공사)가 설립되었다. 1980년대에는 관련된 장비와 시추기술의 발 달로 수심 2,290m에서 성공적으로 시추하 고 수심 600m에서도 생산이 가능하게 되었 다. 1981년 해양에서 처음으로 수평정이 Elf 에 의해 시추되었으며 1982년에 알라스카 해양에서는 인공적으로 섬을 만들어 육상에 서와 같이 시추하는 기법이 시도되었다. Shell이 미국 멕시코만 412m 수심에 역사 상 가장 큰 해양구조물인 고정형 플랫폼 Bullwinkle을 설치하였고(1988년) 총 63,000톤의 철재가 사용된 것으로 알려져 있다. 국내에서도 한국가스공사가 설립 (1983년 8월)되었고 1986년 10월에 국내에 최초로 액화천연가스(LNG)를 도입하였다. 1990년대 이후는 메이저회사들의 심해유전 개발 열정과 기술개발로 시추 및 생산 기술 이 급격히 발전하였고 시추선의 규모도 대형화되었다. 1994년에는 Auger TLP(Tension Leg Platform)가 수심 872m에 설치되었다. 고정형 플랫폼이 아닌 TLP를 사용하므로 Bullwinkle플랫폼보다 더 적은 36,500 톤의 철제로도 더 깊은 수심에 사용할 수 있었다. 1997년에는 수심 1,500m 이상에서도 석유자원의 생산이 가능해졌다. 1997년에는 해양유전의 첫 번째 대규모 성공사례라고 할 수 있는 Marlim 분지에 대한 개발이 Petrobras에 의해 이루어졌다. 2000년대를 지나면서 더 깊은 심해유전을 경제적으로 개발하기 위한 많은 기술적 발전이 있었다. 현재는 시추선의 경우 인도해양에서 달성한 3,165m(2013년), 반잠수식의 경우 미국 멕시코만의 2,728m(2004년) 를 최고 시추수심 기록으로 가지고 있다. 이와 같은 대기록에도 불구하고 심해유전의 시추와 개발은 쉽지 않다. 비싼 일일운영비와 장비운영의 어려움 그리고 사소한 문제가 큰 문제로 발전할 가능성으로 인하여 수 심 1,500m 이상의 심해시추는 여전히 어려운 것이 사실이다. 심해시추의 경우 해양라이저(marine riser)를 포함하여 육상시추에서는 사용하지 않는 여러 장비들을 사용 하는데, 이러한 장비들은 수심이 증가함에 따라 용량이 급격히 증가한다. 해양환경에 의한 영향을 무시할 수 없으며, 환경과 관련된 여러 문제점들이 복합적으로 작용하여 심해시추 비용을 크게 증가시킨다. 또한 세계경제의 글로벌화로 특정 회사나 국가에서 야기된 경제위기는 유가를 급등락시킨다. 2008년 WTI의 가 격이 배럴당 $147에서 6개월 만에 $30로 하락한 것은 그 좋은 예이다. 이러한 어려움을 극복하고 석유자원 개발을 성공적으로 이루기 위한 심해시추 및 시추신기술에 대한 연구가 지금도 활발히 이루어지고 있다. IV. 결언 석유의 매장량은 매년 40년 내외로 발표되지만 석유는 향후 100년 이상 인류의 주력 에너지가 될 것이다. 요즘에는 전 세계적인 석유수요 증가와 석유업계의 지속적인 노력으로 기술적 또는 경제적 이유로 과거에는 개발되지 않았던 한계유전, 심부유전, 심해유전, 신석유자원의 개발이 활성화되고 있다. 또한 안전과 환경에 대한 관심이 증가하면서 관련 법률이 강화되는 추세이므로 이를 고려한 사업계획이 필요하다. 해양에서 석유자원을 성공적으로 개발하기 위해서는 여러 분야의 종합적 협업이 필요하다. 먼저 안전하고 경제적인 시추를 통해 석유부존을 확인하고 매장량을 평가하는 것이 필수이다. 파악된 매장량과 저류층 조건에 따라 적절한 생산시설을 완공하는 해양플랜트 분야는 구체적이고 공학적인 설계와 시공이 필요하다. 하지만 이 분야는 다양한 조건을 모두 고려해야 하여 기술 집약도가 높고 실적에 따른 진입장벽이 있다. 따라서 해양플랜트 분야의 진출을 위해서는 개발대상이 되는 석유에 관한 지식, 다양한 조건과 개발 시나리오에 대한 설계, 구체적 제작과 시공을 위한 절차가 모두 필요하며 이는 각 분야의 긴밀한 협업으로만 가능하다. 참고 문헌 1. 최종근, 2012, 해양시추공학, 2쇄, 씨아이알출판, 서울. 2. 최종근, 2008, 화석에너지의 현재와 미래: 석유 40년 후면 고갈될까?, 서울공대, Vol. 69, p. 26-28. 3. 최종근, 2006, 땅속의 보물 석유자원의 개발과 활용, 대한토목학회지 자연과 문명의 조화, Vol. 54, No. 12, p. 56-60. 4. 최종근, 2006, 땅속의 보물 석유와 석유탐사, 대한토목학회지 자연과 문명의 조화, Vol. 54, No. 11, p. 56-62. 5. 최종근, 2006, 초심해시추와 유정제어, 석유, Vol. 22, No. 1, p. 135-158. 6. 최종근, 2000, 석유공학의 초기 역사, 석유협회보, 1 2월호, 대한석유협회, 서울, p. 82-84. 012 013

l Special Theme l OFFSHORE 유 선 일 Senior Customer Service Manager DNV Korea I. Introduction Increased prices from conventional sources of fossil fuels means obtaining energy from unconventional areas, such as offshore, is becoming a more economically viable option. This has been evident in the increased exploration, development and production of oil and gas from offshore fields in recent years. The offshore market reached USD 227 billion, up 12% from 2011 before. The subsea segment was the most growing segment, followed by the reservoir and seismic and the EPC and topside equipment segment. Field development activity is steaming ahead and will contribute to growing the total market from an anticipated USD 254 billion in 2012 to a level of USD 350 billion by 2016. Brazil, the US Gulf of Mexico, the UK and Australia will be the most important growth markets towards 2016, as large projects in these regions are matured towards production. The onshore market also grew in 2011 reaching USD 255 billion, up 6% from 2010. The LNG segment was the fastest growing segment; this growth was primarily driven by large Australian developments like Gorgon, Queensland Curtis and GLNG. Although not with as steep a growth curve as for offshore, the onshore market is forecasted to grow from an anticipated USD 283 billion in 2012 to a level of USD 330 billion by 2014. The 2014 level is expected to be maintained in 2015 and 2016. The Trend of Offshore Technology mb/d in 2011 - and predicts oil demand will average 90.7 mb/d in 2013. Near term forecasts of oil consumption by other agencies are similar to that of IEA. The EIA in February said it expects global crude oil and liquid fuels consumption to grow from 89.2 mb/d in 2012 to 90.2 mb/d in 2013. Further growth of 1.6 % is forecast by EIA in 2014. OPEC in its February oil report estimates that world oil demand in 2012 averaged 88.8 mb/d, an increase of 0.9 % over 2011. In 2013, OPEC is forecasting a1.0 % year-over-year increase in global oil consumption. Despite the economic and financial turmoil in Europe and the sluggish recovery in the U.S. economy, crude spot prices have remained relatively strong. WTI crude is trading in mid- February 2013 around $93. Brent crude is trading around $114, with the large spread reflecting local crude demand/supply conditions in North America and Europe. Brent is more representative of international pricing. The futures market reflects a consensus view of where the price of oil will be at various dates in the future over the coming decade. Futures trading is now saying that crude prices will be in the range of $83 to $91 per barrel over the next five to eight years. 2) Gas market overview The gas industry continues to evolve with the discovery, classification of different types of gas over the past ten years. The growth in seaborne trade in LNG has been remarkable but recent developments in Shale Gas and Fracking technology has changed the landscape for the global trade and underpinned recent price developments. Gas remains firmly placed as one of the world s preferred energy sources - in 2010, 24% of global energy consumption came from gas. Although this is lower than oil (35%) and coal (24%), gas is seen as a cleaner fuel than its more polluting fossil fuel siblings. Consequently, in a world which is trying to shift toward greener, low-carbon energy alternatives this has worked in favour of the gas industry. A new generation of power stations has emerged with gas-fired operations to replace more antiquated oil and coal facilities. Traditionally, prices for gas have reflected price fluctuations in the oil market. However, correlations between the two have become less obvious in recent times as gas has become more of a commodity in its own right. This is especially a result of the advent of LNG which has become commoditised and is now traded all around the world. The International Energy Agency recently doubled its estimates on the length of time gas reserves would last at current usage levels, raising their expectations significantly. According to the IEA, gas reserves are currently estimated to be assured for approximately 60 years. However, new methods of extracting natural gas may boost this by another 60 years. Furthermore, a reasonable proportion of these new reserves are thought to be offshore. 1. Oil and gas market overview 1) Oil market overview According to world oil demand grew at an annual rate of 1.1% in 2012 and is expected to grow another 1.0 % in 2013. In February Oil Market Report, IEA estimates that global oil demand in 2012 averaged 89.8 mb/d vs. 88.9 II. Trend of offshore market 1. Global offshore market The offshore markets grew from 2006 to 2008. The market softened in 2009 when the financial crisis contributed to a fall in the oil price from 97 USD/bbl to 62 USD/bbl. The relatively modest overall decrease in 2009 was lower 014 015

[Fig-1] Global offshore market (Source: INTSOK, DNV) USD billion 400 350 300 250 200 150 100 50 0 than many analysts forecast in 2008. There was a dramatic decline in activity in GoM(Gulf of Mexico) in 2010, but this was offset by growth in other markets. Overall spend is expected to reach USD 254 billion in 2012 as conditions in GoM normalize and growth continues in other key regions. The target markets are forecasted to grow to a level of USD 350 billion by 2016. Between 2006 and 2008 the offshore market experienced growth in all segments, and grew by an average 16% per year. The decrease between 2008 and 2009 was mainly driven by a drop in field development activities reflected by lower well, subsea and EPC and topside equipment spend. However, the subsea and EPC and topside equipment segments are anticipated to be the segments with the highest growth rates going forward with respectively 17% and 11% average annual growth rate from 2012-2016. 2. Offshore EPC and topside equipment In 2010, EPC and Topside Equipment expenditure offshore in the markets grew, after a slight decline the previous year. Going forward, the main markets are forecasted to grow the most with an average annual growth rate of 15% from 2012-2016. Total market for EPC and topside equipment in 2016 is forecasted at almost USD 70 billion. We should note that the EPC and Topside Equipment market includes facility modification, as modification projects tend to be awarded in a similar fashion as new build platforms or floaters, i.e. in the form of Engineering, Procurement, Construction and Installation (EPCI) contracts or similar. Modifications are needed in order to replace old equipment and modules or to accommodate tie-backs of smaller fields. The modification market is steadily increasing globally as facilities age. 3. Subsea 2006 Operations Well Subsea 2007 2008 2009 2010 EPC and Topside Equip. Reservoir & Seismic [Fig-2] Offshore EPC and topside equipment market (Source: INTSOK, DNV) USD billion 40 30 20 10 0 2006 2011 Systems, Equip., Piping & Valves Procurement, Cons. and installation Engineering 2007 2008 2009 2010 2011 2012 2012 2013 2013 2014 2014 2015 2015 2016 2016 In 2009 Subsea expenditure in the markets decreased slightly. The market kept the 2009 level in 2010 and grew once more in 2011. Overall spend has increased from USD 18.5 billion in 2006 to USD 30 billion in 2011 driven by growth in most markets, especially in Angola, Brazil, US GoM and the United Kingdom. As growth continues going forward, markets are expected to reach USD 66 billion of annual subsea spend by 2016. Growth in the years ahead will be driven by activity in mature markets such as the United Kingdom, as well as emerging markets such as Brazil and Australia. The installation related segments, SURF and Subsea Equipment, dominate the subsea market. These segments are also the ones that will experience the most growth with more than a doubling in demand in 2016 compared to 2011. This demand growth will only be possible to meet if suppliers act to expand capacity, and this is exactly what seems to be happening at the moment. The smaller Subsea Services market will also experience high growth. This segment is driven by the average age of the installed base of subsea equipment, flow lines and trunk lines. The Subsea Services market is expected to grow to USD 7.8 billion in 2016, an increase of more than 70% from 2011 levels. 4. Offshore well The offshore well market grew from 2006-2008 reaching a high of USD 70 billion in 2008. In 2009 the market softened before it grew slightly again in 2010. 2012 is expected to be a good year and expenditure in this segment is expected to reach USD 90 billion. From 2012-2016 the growth is coming from deep and ultra-deep waters while spending on shelf is forecasted to be rather constant. The offshore well expenditure in the markets is forecasted to reach USD 112 billion by 2016. [Fig-3] Subsea market (Source: INTSOK, DNV) The Rigs and Drilling Contractors segment plays a particularly important part in delivering on the expected growth in this market as this segment is the market enabler of the other two segments, Down-hole and Well Services and Drilling Systems and Equipment. In spite of the recent building boom there will be a need for more rigs by the end of the forecast period. If these rigs are not built, demand for well-related services will not be met. USD billion 40 35 30 25 20 15 10 5 0 2006 Subsea Services Subsea Equipment SURF 2007 2008 [Fig-4] Offshore well market (Source: INTSOK, DNV) USD billion 70 60 50 40 30 20 10 0 2006 2009 2010 Downhole and Well Services Drilling Systems and Equip. Rigs and Drilling Contractors 2007 2008 2009 2010 2011 2011 2012 2012 2013 2013 2014 2014 2015 2015 2016 2016 016 017

5. Offshore operations The offshore operations expenditure in the markets grew to USD 52.9 billion in 2008. 2009 saw a drop to USD [Fig-5] Offshore operations market (Source: INTSOK, DNV) USD billion 100 80 60 40 20 0 2006 Decommissioning Logistics EI&T 2007 2008 2009 2010 Maintenance Operational ServicesServices 6. FPS(Floating Production Systems) market [Fig-6] 6 FPS market by field development solution (Source: INTSOK) USD million 40,000 30,000 20,000 10,000 0 2006 Fixed + floater TLP Spar Semi FLNG FPSO 2007 2008 2009 2010 [Fig-7] Number of field start-ups with floating facilities (Source: INTSOK) USD million 30 20 10 0 2006 Fixed + floater TLP Spar Semi FLNG FPSO 2007 2008 2009 2010 2011 2011 2011 2012 2012 2012 2013 2013 2013 2014 2014 2014 2015 2015 2015 2016 2016 2016 52.5 billion due to delays in planned green and brownfield projects as operators cut their budgets in the wake of the financial crisis. The growth continued in 2010 and the market is expected to grow towards a level of USD 83 billion by 2016. Growth is expected across all markets going forward, but the maintenance services market will continue to be the largest market for the foreseeable future. The decommissioning market will continue to be small compared to other market segments. The FPS market has seen significant growth in recent years, with the total market growing from USD 7.7 billion in 2006 to USD 12.5 billion last year. 2011 was the first year of increase in spending, after a period from 2008-2010 with slightly negative growth. Going forward, solid growth is expected, with the market reaching USD 31.3 billion in 2016. At this point, Africa will have overtaken South America as the largest market, while Australia, an emerging FPS market, will have risen to become the third largest market globally. The dominant type of FPS is the Floating Production, Storage and Offloading (FPSO) vessel that constituted over 70% of the FPS market in 2011. While the FPSO market traditionally has been dominated by converted tanker vessels, there is an increasing trend towards purpose-built FPSOs. These are designed for given field developments, and can handle increasingly complex field developments, in terms of deeper water, harsher climate, and more complex subsurface and reservoir conditions. While the FPSO has been the dominant floating solution globally, the regional markets differ. While production semis have mainly been used in North America and Europe, the TLP market is confined to North America and Western Europe. A TLP has a hull similar to a floating drilling rig, but with tension legs anchoring the platform to the seabed. While the Spar platform so far has been a Gulf of Mexico phenomenon, the Aasta Hansteen field in the Norwegian sea is about to get developed with a Spar platform. Spar platforms tend to be used at developments in ultra-deep water. An interesting development in the floating production market the last years has been the emergence of Floating Liquefied Natural Gas (FLNG) facilities. While no fields have been developed with an FLNG solution yet, several key players are assessing it for new developments, with Shell being a frontrunner with its Prelude FLNG project, where the investment decision was taken last year. However, this spring Petronas joined the race for the world first FLNG, with a planned unit for its Kinawit field with planned start up in 2015. 7. Rig market The global mobile offshore drilling rig fleet has grown from a level of approximately 600 rigs in 2006 to close to 800 in 2011. During the period leading up to the financial crisis there was a boom in new build orders which came to an abrupt stop when the financial markets plummeted. However, from the fall of 2010 new build activity picked up again and currently there are more than 100 rigs that are firm orders going towards 2016. The global fleet is sufficiently large to deliver on demand up to 2015. From 2015/2016 demand will outstrip supply unless new rigs are built. These rigs will need to be ordered from 2013 onwards to be completed in time. Demand however depends on new acreage being awarded, with ensuing exploration and development activities. [Fig-8] New build offshore drilling rigs by delivery year (firm and modeled) (Source: INTSOK) USD million 70 60 50 40 30 20 10 0 2006 Drillship-firm Drillship-modeled 2007 2008 2009 Semi-firm Semi-modeled 2010 2011 2012 Jack-up-firm Jack-up-modeled [Fig-9] Global offshore drilling equipment market for mobile units by rig (Source: INTSOK) USD million 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 2006 Drillship Semisubmersible Jack-up 2007 2008 2009 2010 2011 2012 2013 2013 2014 2014 2015 2015 2016 2016 018 019

With no new acreage awards, the current fleet will be large enough to cover demand. Key regions for growth include Brazil, Gulf of Mexico, West Africa and Australia. However, multiple other regions are emerging with new exploration activity; hotspots include West Africa Transform Margin (starting in Ghana), East Africa (deep water gas discoveries), Indonesia and Greenland. The number of countries with deep water production could increase from the current 32 to more than 90 by 2025. The offshore drilling equipment market experienced strong growth in the period from 2006-2009, going from USD 1.6 billion in 2006 to USD 4.4 billion in 2009 as new build activity increased sharply. The market softened somewhat during the financial crisis, but rig owners started contracting rigs again in the fall of 2010. Current firm orders in combination with a forecasted increase in demand in the second half of the decade will result in an increase in the market for drilling equipment from 2013. There is a possible upside in the number of new jack-ups needed due to potential new regulations following the Macondo incident which may result in older units being phased out. III. Floating production systems 1. Floating production storage and offloading vessels (FPSOs) 1) FPSO overview The oil industry can be slow to accept new ideas, and this was certainly the case with Floating Production, Storage and Offloading System (FPSO) vessels. The first FPSO was installed on the Castellon field in 1977, but it took another 15 years until this technology gained wide industry acceptance. FPSOs have now become a base case solution for development of remote offshore oil fields in most areas of the world, and especially for deepwater and ultra-deepwater applications. FPSOs typically perform the same functions as an offshore production platform, including separation and treatment of produced hydrocarbons into commercial products, treatment of produced water to permit overboard disposal or reinjection, and injection of treated seawater into the reservoir for pressure maintenance. However, whereas a platform generally pumps produced oil into a pipeline or to a remote loading terminal, the FPSO stores oil on board the unit, and periodically offloads this directly to a shuttle tanker either moored in tandem or moored to an adjacent loading terminal. FPSOs come in a variety of sizes, shapes, production capability and cost. They range from relatively small units with 30,000 to 50,000 b/d processing plants to mega units capable of processing 250,000 b/d and greater. Most units are ship shape, but a few cylindrical FPSOs are also in service. Some FPSOs are fitted with external or internal turrets to weathervane, others are spread moored. Some are designed to permanently remain on field, some to be quickly disconnected. CAPEX for an FPSO can range from $200 million to $2.0 billion+, depending on production plant capacity, design life, operating environment and other factors. FPSOs have field storage capability and can be used in locations economically inaccessible to pipeline infrastructure. Water depth is not a constraint - FPSOs operate [Fig-10] 1st purpose built FPSO: Petrojarl I 1986 (Source: DNV) on shallow to ultra-deep water fields. They also operate in environments ranging from benign harsh. FPSOs are less weight sensitive than other floating production systems and the extensive deck area of a large tanker provides flexibility in process plant layout. Surplus and aging tanker hulls can be used for conversion to an FPSO. FPSOs can be modified and redeployed following field depletion. Units fitted with quick disconnect turrets can be moved during typhoon/hurricane activity. Leasing of FPSOs has evolved into a well-accepted procurement practice to transfer financing, construction, residual value and operational burden to a contractor. But subsea tiebacks associated with FPSOs generally bring higher well maintenance costs. Complex turret/swivel machinery used on weather vaning FPSOs is expensive and failure of the turret/swivel can be a major problem. Use of older tanker hulls for conversion can cause unexpected cost overruns and delays. Redeploying an FPSO is not as easy as it may appear. Each field is different, often requiring modifications to processing plant and mooring system. 2) The technology of FPSO FPSO is the design of choice for many offshore areas from small marginal fields to ultra-deep large complex fields remote from any oil and gas infrastructure. The advantage is that the facility is stand-alone, has storage capacity, is flexible (can add satellite fields) and is capable of relocation when the field is exhausted. A FPSO is essentially an anchored tanker which receives produced fluids from multiple underwater wells. The incoming fluids from the sub-sea wells are a mix of oil, gas, water and sand. FPSO topside facilities provide onsite processing to separate the mix into marketable products and manageable by-products. The fluids from deepwater reservoirs hold a myriad of potential problems and often require complex treating facilities. The topside facilities main function is to separate the gas and water from the oil; treat the gas to meet specifications for export, re-use on board as fuel, and/or re-injection into the reservoir; and separate and deoxygenate the produced water before it is pumped back into the reservoir. The degassed and dewatered oil is stored in the hull of the vessel and periodically offloaded to shuttle tankers. 1 FPSO topside standardisation concept FPSO designs, whether based on converted tanker or new-build hulls, are governed by a number of key technical factors: typically the storage capacity, production capacity, export capacity, site environment and crew complement. However, a key non-technical factor affecting the entire project organisation and major technical decisions is proj- 020 021

ect schedule which is a significant challenge for designers. There is a need for a fast track method for building or converting FPSOs. However, it is unreasonable to expect to simply squeeze indefinitely all project activities to achieve significantly reduced delivery times: this would result in unacceptable risks during design and construction, with commensurate risks to the performance of the unit. 2 Design procedure of standard FPSO topside The conflicting requirements have triggered an alternative approach to manage a fast track and multiapplication FPSO project, the so-called Generic or Standardised Approach. Topside For the standardisation of FPSO designs, engineering companies have started looking into developing a decision support tool to find the best FPSO design to be less sensitive to the integration process of the hull with the topsides. There are numerous ongoing research programs to come up with solutions for modularising the entire topside with the objective to minimise sensitivity to the integration of topsides with the hull. However, there could be a scope available to develop a different design decision tool, which would assist in minimising time for the design of the topsides based on constraints and conditions enforced by the design philosophy and field data (well fluid pressure, light/heavy oil, composition, etc.). This decision tool could expedite the engineering work when there are a few FPSO projects going on concurrently. FPSO design hierarchy is considered, the first input data and information for all design sub-sections (Subsea Infrastructure, Turret & Mooring, Topsides Production, Hull & Storage and Mooring) comes from the General Design Philosophies enforced by the client. There is a second set of design philosophy data provided by the client which is specific for each sub-section. Once the two sets of information is provided for the topsides design team, this information is fed to the decision support tool. The availability of firm design data is essential for FPSO design as nearly all FPSO projects suffer severe delay and incur additional costs due to changes in the design at a very advanced stage of the project. 3 FPSO design philosophies Before the detailed FEED, for a FPSO gets underway, the project statement of requirements and the basis of design documents should be in place as a minimum. They provide a high level route map for the project management and engineering teams on the overall objectives for the project. The next level of the route map will be provided as a series of strategies/design philosophies. The strategies/philosophies listed below are deemed to be the principal ones which can provide an overall design plan, not just for production systems or marine systems but for the FPSO as a single entity. Safety management Environmental strategy and management Cargo management Area classification Heating, ventilating & air conditioning, HVAC Electrical Controls Noise and vibration Corrosion management Isolation for maintenance These philosophies serve as a focal point to which all design groups can refer. They are therefore, an essential tool for both global design consistency and effective interface management. Hence, the mentioned strategies would be the first input to the design of all the sections including topside processes. And the main parameters that define the topside design plan might be as follows : Reservoir characteristics FPSO motion Storage capacity and hull size Choice of oil and gas export system Single or twin production trains Decommissioning, abandonment and possible redeployment A. Reservoir characteristics Field reservoir characteristics have a major influence and the facilities designer therefore needs to have good quality information such as well fluids composition, thermodynamic condition, reservoir structure, etc. High confidence levels in reservoir data are necessary to minimise the possibility of late design changes. B. FPSO motion The movement of a FPSO by sea-wave motions should be considered in any topside design as there is an impact on the equipment performance onboard the vessel. Even when the sea is calm and when the FPSO is moored / anchored to the seabed, the seawaves generated could still have impacts such that sloshing and mixing. These impacts can be expected in equipment like separators and coalescers onboard an FPSO. Specialised software (proprietary software like FLUENT) is used to study the effect of sloshing and mixing in these equipment and modifications are made (for example, it is recommended that additional longitudinal baffles be installed at appropriate distances within the separator to help mitigate the effects of sloshing and mixing of the multiphase liquids). 022 023

C. Storage capacity and hull size It is well known fact in the FPSO industry that a major problem in a FPSO projects, is the integration of the topside deck with the hull. Hull size is important for FPSO topside design because of two reasons i.e. crude storage capacity and deck layout. The FPSO vessel may be new-build or converted. For a newbuild FPSO, the process design and storage planning can first be arbitrarily done and then based on the planned storage capacity and deck layout, hull design can be pursued. Where crude oil is exported via pipeline or stored in a separate FSO, there is just minimum buffer storage for safety issue. In such conditions, a minimum hull size can be selected provided it satisfies the required layout for topsides facilities. For newbuilds, it may be economically attractive to increase hull size rather than constrain topsides deck area. When an existing vessel is dedicated for a field, the storage planning and process layout will be dictated by the vessel s condition. In this condition, process layout may be squeezed or multiple decks are planned. For storage, if the selected vessel has less than the required storage volume, the frequency of shuttle tanker is to be increased. D. Choice of oil and gas export system Oil can be exported directly via a shuttle tanker or via a high pressure pipeline into a larger pipeline gathering system. Oil can also be exported indirectly via a lower pressure pipeline to an FSO in the vicinity of the field. The selection of direct export into a pipeline system will depend on the availability of riser technology appropriate to the water depth, the flow rates, system pressure and distance to market. Gas export options are becoming diverse. Currently, the only way to transport gas from a FPSO to market is via subsea pipelines. There are other gas utilisation alternatives such as LNG, CNG, GTL, NGH and GTW that because of extensive process requirements and FPSO layout limitations cannot usually be integrated to the same FPSO and requires another dedicated gas FPSO. The oil and gas export options have significant impact on topsides processes as the final product (export oil or gas) quality depends on the export system. For example the quality of crude oil to reach subsea pipeline specification is different with that of a shuttle tanker. However, the selection of oil and gas export system is a matter of economics and is essentially related to the amount of product. E. Single or dual production trains There could be two different topsides design methodologies i.e. a single 100% production stream or dual trains of 2 50% capacity handling. The advantage of the former is lower cost but with risk of inflexibility in case of any equipment malfunction. Thus this critical equipment requires a spare. The dual process has high level of safety and operational flexibility, but with the disadvantage of high cost. The selection of any methodology requires technoeconomical study and is defined by client. F. Decommissioning, abandonment and redeployment The main advantage of FPSOs is redeployability. Usually FPSOs are not staying in a specific field for their whole life and are redeployed to another field after a few years when the field production reaches the minimum profitable level. It is therefore important that, at the time of FPSO design, the other known or probable fields are also considered. This could help the designer to configure required space for future equipment with respect to design flexibilities. 2. LNG FPSO; Floating liquefied natural gas vessels (FLNGs) 1) LNG FPSO overview In the last decades, the international natural gas market has been growing at a very high rate and continues to increase. Traditional offshore production platforms for natural gas have been exporting the partially processed natural gas to shore where it is further processed to permit consumption by end-users. Such an approach is possible where the gas field is located within a reasonable distance from shore or from an existing gas pipeline network. However, much of the world s gas reserves are found in offshore fields where transport via a pipeline is not feasible or is uneconomic to install and therefore, to date, it has not been possible to develop these fields. During the past four decades studies have been carried out on offshore liquefied natural gas production options. This has resulted in a new kind of production facility called LNG floating production storage and offloading (LNG FPSO). The benefits are a platform which does not need much external support and which allows for the transformation of gas into a readily transportable form, i.e. LNG. When the gas field is depleted the production platform can be moved to a new gas field. To date, no LNG FPSO has been built. However, several concepts exist and have been planned to be built. Concerns about global warming have been raised worldwide and governments are attempting to find strategies for decreasing emissions of greenhouse gases. When burned, natural gas emits lower quantities of greenhouse gases and criteria pollutants than other fuels and is therefore seen by many to have a key role in strategies for lowering carbon emissions. LNG FPSOs could contribute further with a reduced environmental footprint compared to an onshore LNG plant, with an associated offshore platform, that would require a significant land-take and possibly coastal dredging. In addition, LNG FPSOs also have the possibility of being relocated to other locations. LNG FPSOs are floating gas liquefaction plants mounted on large shipshape or barge hulls with internal storage, designed to be positioned on or near a major subsea natural gas resource or moored in a location where gas can be received from an onshore gas source. They are the newest type of floating production system - and also the most complex and costly floating production units designed to date. 024 025

LNG FPSOs are intended to be utilized at the origin of the LNG supply chain. They avoid the need for pipeline infrastructure to transport gas from fields distant from shore. They also do not occupy valuable real estate, can be built as serial units in a shipyard, commissioned before leaving the shipyard and avoid not in my backyard environmental opposition to LNG production plants. LNG FPSOs can also be relocated following field depletion - but significant changes to the pre-cooling plant will likely be required to meet new field gas characteristics. On the negative side, LNG FPSO designs incorporate technology not yet proven in commercial service and there are technical issues associated with LNG FPSO topside plant size and weight still to be resolved. Separation processes in LNG production are sensitive to vessel motion, which limits use in open sea environment. Safety of LNG FPSOs and their insurability remains to be proven. 2) The technology of LNG FPSO LNG FPSOs are offshore floating production units that contain both gas processing and liquefaction equipment as well as storage for the produced LNG. The unit could have a fixed mooring or be equipped with a turret, external or internal, that will allow the unit to weathervane. On top of the main deck, a supporting structure, called the topside, is installed, which contains the gas processing and liquefaction equipment. The raw natural gas is transferred from the wells in risers and diverted to the topside through a turret, if equipped with a connection along the side of the hull. The produced LNG is then [Fig-11] 1st LNG FPSO (Source: Shell) transferred from the topside to cargo tanks situated below deck. The stored LNG is frequently transferred to arriving LNG carriers via offloading equipment, which could be located amidships or in the aft of the unit. To provide the crew with living quarters, control room, etc., an accommodation block is needed, and this could be situated on the deck in front or aft of the topside. 1 Structure The main structure of LNG FPSOs will be of similar design as oil FPSOs and oil tankers and could generally follow the principles of the design of steel ships. Due to similarities to tankers with regard to structural arrangement, many reliability formulations developed for ships could be applied to LNG FPSOs. The design of an offshore structure will, however, have additional requirements compared to a ship. Due to continuous operation and the absence of regular docking, additional attention needs to be drawn to corrosion prevention. To ensure the structural integrity, corrosion-protective coating and cathodic protection could be used. For critical structural members, corrosion allowance should be used as a safety factor in design. Additional loads on the hull structure from the topside and mooring equipment need to be accounted for in the design. Depending on the intended capacity of the LNG FPSO the weight of the topside could exceed 70, 000 tons for a large production unit producing between 3-5 million tons per annum (MTPA). Today, there are two different mooring systems in use for permanently moored offshore structures, spread mooring and turret mooring. The additional load will affect internal major load-carrying structural elements, such as longitudinal and transverse bulkheads, and, depending on the system used, the load will be taken up by different areas on the hull. Spread mooring constrains the vessel in one direction and is typically equipped with chain stoppers distributed along the main deck of the hull. A turret mooring system could be fitted externally or internally of the structure and will affect the structure in its vicinity. 2 Gas processing and LNG production Raw natural gas can have a wide variety of compositions. Natural gas is often found together with oil in the same reservoir. One of the first steps in the process is to examine which contaminates that are present in the entering gas stream. Therefore, an LNG process plant can differ between locations depending on the technique used to process the gas to reach a pure state. A. Reception When the raw natural gas is brought up from the wells the first step is to separate erosive solids, water and condensate. Erosive solids, for example sand, could damage or tear piping and components. The separation could be achieved by three principles; momentum, gravity settling or coalescing. The technology used is dependent on the composition of the raw natural gas. Condensate is separated from the gas stream and routed to the condensate stabilizer. B. Condensate stabilization Composition of raw natural gas varies between different locations. Heavy hydrocarbon components are normally found to some extent in all gas reservoirs in its liquid state. In underground pressure they exist in a liquid state and will become gaseous at normal atmospheric pressure. In its liquid state these hydrocarbons are called hydrocarbon condensates which to a large percentage consist of lighter components. When brought up to atmospheric pressure these lighter components will flash off and therefore there is a need to stabilize the recovered hydrocarbon condensate to avoid flashing in storage tanks. Flashing occurs when a liquid immediately evaporates to vapor undergoing reduction in pressure. Stabilization could be achieved either through Flash vaporization of Fractionation. C. Acid gas removal To avoid damages on the equipment further down in the process, sour gases such as CO2 and H2S are removed from the flow. This could be done with various processes depending on concentrations of contaminants in the gas 026 027

and the degree of removal desired, temperature, pressure, volume and composition of the gas, etc. Two general processes are used for removal; adsorption or absorption. Adsorption concentrates the impurities on the surface of an absorbing medium, usually granular carbon solid, while absorption relies on physical solubility of the impurities into an absorption medium. The collected CO2 could be released into the atmosphere, but this may not be desired due to environmental policies of the operator or not permitted by regulations of the site of operation. Re-injection to underground storage could be an option for the collected CO2. D. Dehydration and mercury removal To avoid freezing damages to pipes and equipment due to the formation of hydrates, water is eliminated from the flow. The most common techniques to dehydrate gas is by injection of a solid or liquid desiccant or by refrigeration. The technique most preferable for offshore use is solid bed dehydration due to a relatively small footprint and being unaffected by vessel motions. If mercury is present in the gas flow it can cause corrosion of aluminum, therefore, it is also removed to avoid damages. The removal of mercury can be achieved by adsorption or by a bed filter. E. Removal of liquefied petroleum gas (LPG) LPG is a flammable mixture which consists of mostly propane and butane. For offshore use the preferred method for removal of LPG is fractionation. The amount of LPG presence in the gas flow will be an important factor. A large amount of LPG products can be produced for sale or used as fuel for power generation on board. A small amount of LPG in the raw gas is expensive to remove and could not fulfil the fuel consumption on board or is unprofitable to sell. The fractionation train normally, depending on the composition of the raw natural gas, consists of three stages where the lighter product is boiled of in each stage. Deethanizer: In the first step ethane and propane is separated, the ethane goes overhead and propane and heavier components are extracted from the bottom and sent to the depropanizer. Depropanizer: In the second step the propane is separated, the propane now goes overhead and isobutene and heavier components are extracted from the bottom and sent further to the debutanizer. Debutanizer: In the last step butanes are separated from the flow leaving natural gasoline from the fractionation train. Mixed refrigerant process: A single mixture of nitrogen and hydrocarbons is used as refrigerant to cool the natural gas. The mixture is composed to match the cooling curve of the natural gas. Cascade refrigerant process: The natural gas is cooled in three steps using different refrigerants for each step. Propane is used in the first step to the precool gas, secondly ethylene or ethane is used to bring the gas down to its liquefaction temperature. In the final sub-cooling step methane is used to cool the gas. Expander processes: The natural gas is cooled in a heat exchanger process with either methane or nitrogen as refrigerant gas. The refrigerant gas is cooled in a compression expansion cycle. For offshore application, an expander process utilizing nitrogen as cooling medium would be preferable due to its small form factor and to its being less sensitive to motion than the other techniques. Other advantages of the technology are higher safety and that it is easier to operate compared to the others. Generally, the expander process has higher power consumption and poorer economy compared to cascade and mixed refrigerant processes. 3 Transfer systems The wellheads are either placed sub-sea directly on the well or on the LNG FPSO. If placed sub-sea, a flow line transports the raw gas from the wellhead to the LNG FPSO via risers. The LNG FPSO is usually tied to multiple sub-sea wells. Depending on the harshness of environment of the intended location and the need to disconnect from the risers, the LNG FPSO could be equipped with a turret which the risers are connected to. The offloading is an important part of the LNG FPSO. The produced LNG must be offloaded onto an LNG carrier arriving periodically. The design of an offloading system can be divided into two main categories, side by side and tandem. A. Side-by-side transfer The transfer of the LNG is performed via rigid connection arms located on the side of the LNG FPSO. The operation is normally supported by tugboats. Up to four tugboats could be required to get the carrier alongside the LNG FPSO. Calm weather is required for this offloading system since the loading arms do not allow for a wide range of relative motion, and this limits the window of offloading for many locations. The advantage of this solution is that conventional LNG carriers could use their standard amidships manifold without modification, which minimizes the cost. F. Liquefaction The liquefaction cools the clean feed gas in normally three steps down to its storage temperature of -160 to -163 C. When liquefied the natural gas is equivalent to 1/600 of its volume in a gaseous state. There are three main technologies, mixed refrigerant processes, cascade refrigerant processes and expander processes. B. Tandem transfer There are several different technologies available. The benefits of tandem transfer are less influence from relative motion between the LNG FPSO and the shuttle tanker. The tandem transfer technique allows for a more severe sea state than side-by-side transfer, which makes it preferable if the location of the LNG FPSO is under the influence of harsh weather. 028 029

IV. Offshore drilling unit- centred fixed platform and jack up The growth and evolution of offshore drilling units have gone from an experiment in the 1940 s and 1950 s with high hopes but unknown outcome to the extremely sophisticated, high-end technology and highly capable units of the 1990 s and 2000 s. In less than 50 years, the industry progressed from drilling in a few feet of water depth with untested equipment and procedures to the capability of drilling in more than 10,000ft of water depth with well-conceived and highly complex units. These advances are a testament to the industry and its technical capabilities driven by the vision and courage of its engineers, crews, and management. Since the beginning in the mid-1800 s until today, the drilling business commercially has been very cyclic. It has been and still is truly a roller-coaster ride, with rigs being built at premium prices in good economic times and sold for pennies on the dollar in bad times. Mergers, acquisitions, fire sales, and buyouts have occurred throughout its history, yet during all these times, the drilling segment has served the oil and gas industry well. Unfortunately, all this turmoil has been hard on the people involved, but they keep coming back with enthusiasm to this very interesting and stimulating industry. In the early days, public image, safety, and the environment took a backseat to the technical and operational challenges of offshore drilling. Today, however, these issues often drive the whole thrust of drilling activities and operations. The offshore drilling business is now a worldwide, multibillion-dollar business with high visibility that has a strong influence on the world s economic health and people of all nations. One may ask why there are so many types, sizes, and capabilities of offshore drilling units. The answer involves different technical, economic, government, and safety requirements to accomplish a specific drilling program. No one type can satisfy all the requirements for every drilling location; thus, we have to understand all types to make a correct decision on their use. The major types of units are: Fixed-platform rigs Jack ups Tender assist drilling (TAD) Conventional ship-and barge-shaped rigs Submersibles Semisubmersibles Ultra deep water units 1. Fixed platform 1) Types of fixed platform 1 Conventional standard platform rigs These rigs are not self-erecting, not particularly modular in construction, are heavy, and are built to API well spacing standards, so they can work on a wide range of platforms. They usually require a derrick barge or a large platform crane to load and erect. They may take 2 to 4 weeks to erect, and their dry weight will probably exceed 5 Million pounds. 2 Self-erecting, self-loading, and highly modularized Rigs These rigs are set up to go from platform to platform quickly. Generally, they take up much less space, and their dry weight (750 to 1,250 k pounds) is considerably less than that of conventional standard platform rigs. Unfortunately, most of these rigs have limited hook and traveling-block capacity, and sometimes do not have all the auxiliary equipment, such as bulk tanks, large liquid-mud-storage capacity, and emergency power. They are particularly attractive for in-casing workovers and out-of-casing redrilsl. A few of the larger modular rigs have hook load ratings of 1 million lbm but also have compromised weight and ease of mobilization. Modular rigs first appeared in the late 1980 s and early 1990 s. They generally do not have modules weighing more than 30 tons, have a selferecting leap frog crane, contain modules that can be transported on any standard-sized workboat, and can be completely rigged up or down in 2 to 3 days. 3 Modular fixed-platform rigs These rigs, having gained popularity recently, are site-specifically designed and constructed to be placed on deepwater spars and TLPs. They are very compact and lightweight. Their mobilization and rig-up time is much more than that of standard modular rigs. Because modular rigs are generally not self-erecting, cost and total rig-up/rigdown time are issues. 2) Considerations for fixed-platform rigs The first consideration in using a fixed-platform rig, usually controlled by the operator, is whether the platform is large enough and has a high enough load bearing to place and work the rig. This includes : The space and dry weight of the rig itself Wet weigh Mud Operator fixed items Liquids Portable tools, etc Live loads Hook Setback 030 031

Rotary Storage Expendable items like bulk casing and operator supplies Generally, a four-pile structure is the smallest fixed structure that a conventional standard platform can be placed on and work efficiently. Usually, the second consideration is the mobilization method and cost. Numerous platform rigs, when broken down for shipment, cannot fit on a standard workboat, and a derrick barge is required. Modular rigs can usually fit on a workboat. 2. Jacket platforms Offshore drilling units are used worldwide for a variety of functions in different water depths and environments. The fixed offshore drilling units are the most common structures which are used for oil and gas exploration in relatively shallow waters such as Persian Gulf, GoM. The total number of offshore platform in various bays, gulf and oceans of the world is increasing year by year, most of which are of fixed jacket-type platforms located in 100ft (32 m) to 650ft (200 m) depth for oil and gas exploration purposes. Most of the platforms are used in the shallow waters of the continental shelf, so 95% of the offshore platforms in the world are jacket designed. These platforms are fixed and their deck is supported by a steel tubular structure having its feet on the seabed. This steel tubular structure is called the jacket. To fix the jacket onto the seabed, the jacket is equipped with thick steel piles of 2 meters diameter that can penetrate the sea floor up to 100 meters deep to ensure the stability of the whole platform. The jacket may be hundreds meters high and weight thousands tons. [Fig-12] Structure of jacket (Source: DNV) [Fig-13] Offshore drilling units (Source: DNV) Jacket Jack up The analysis, design and construction of offshore structures compatible with the extreme offshore environmental conditions is a most challenging and creative task. Over the usual conditions and situations met by land-based structures, offshore structures have the added complication of being placed in an ocean environment where hydrodynamic interaction effects and dynamic response become major considerations in their design. 1) Structure of jacket platform The steel jacket type platform on a pile foundation is by far the most common kind of offshore structure and they exist worldwide. The "substructure" or "jacket" is fabricated from steel welded pipes and is pinned to the sea floor with steel piles, which are driven through piles guides on the outer members of the jacket. The piles are thick steel pipes of 1 to 2 metres diameter and can penetrate as much as 100 m into the sea bed. The jacket can weigh up to 20,000 tons. To ensure that the installation will last for the required service life, maintenance must be carried out including the cathodic protection used to prevent corrosion. 2) Design of jacket platform Offshore jacket platforms are normally designed using one of the following offshore design codes: API RP2A WSD (American Petroleum Institute 2000), API RP2A LRFD (American Petroleum Institute 1993) or ISO 19902 (International Standards Organization 2007). API RP2A-LRFD and ISO 19902 codes are limit state design based approaches for design of steel jacket platforms. Working stress design by American Petroleum Institute uses a common factor of safety for material. Static nonlinear analysis, i.e. pushover institute uses a common factor of safety for material. Static nonlinear analysis, i.e. pushover analysis, is widely utilized in current offshore standards such as API, ISO and DNV (Det Norske Veritas) to evaluate nonlinear behavior and ultimate capacity of offshore platforms against environmental wave loading. In this method, the jacket platform is subjected to the site specific design wave load, i.e., 100-yr wave and the corresponding load pattern is increased monotonically until the collapse of the structure is exhibited. Dynamic analysis is particularly important for waves of moderate heights as they make the greatest contribution to fatigue damage of offshore structures. The dynamic response evaluation due to wave forces has significant roles on the reliable design of the offshore structure. In the design and analysis of fixed offshore structures many nonlinear physical quantities and mechanisms exist that are difficult to quantify and interpret in relation to hydrodynamic loading. The calculation of the wave loads on vertical tubular members is always of major concern to engineers. The analysis of wave effects on offshore structures, such as wave loads and corresponding responses, are of great importance to ocean engineers in the design, 032 033

and for the operational safety of offshore structures. The effects of various wave patterns on offshore structure have been investigated by numerous researchers in the past. The influence of hydrodynamic coefficients depends on the wave period and the variation is nonlinear between the different wave heights with the same wave period. The height of the jacket is defined by the water depth plus about 15 meters above the sea level. Acting as a cage, the jacket is protecting all the piping going through to the seabed. The tubular structure of a jacket is designed to support multiple constraints : Impact of the waves Pressure of the wind on the topsides Flow of the sea water streams and tides Corrosion Fatigue effect Life cycle time The space tubular frame is also protecting these pipes from lateral load. The deck structure is connected to the jacket by the deck legs transferring efforts both ways. The waves having a period of 14 to 20 seconds, the jacket is designed with a natural period of 2.5 seconds in order to prevent vibrations amplification under the wave effect. As a result of all the requirements imposed to the jacket, its costs may represent up to 40% of the total platform capital expenditure. 3. Jack ups The primary advantage of the jack up design is that it offers a steady and relatively motion-free platform in the drilling position and mobilizes relatively quickly and easily. Although they originally were designed to operate in very shallow water, some newer units, such as the "ultra-harsh environment" Maersk MSC C170-150 MC, are huge and can be operated in 550 ft in the GOM. With 673.4-ft. leg length, a hull dimension of 291 336 39ft, and a variable deck load (VDL) of 10,000 long tons, it is a mammoth and rivals some of the larger semis. This type of unit can be commercially competitive only in the North Sea and in very special situations. 1) Types of jack up unit 1 Independent-leg type jack up unit For the independent-leg units, preloading is required to drive the legs into the ocean bottom before the hull is completely jacked out of the water. During this procedure, the jack ups is at risk from weather and leg punch through ; i.e., one leg breaks through a hard crust, putting the other legs in a large bending movement. Generally, 5ft swells and/or a combined sea of 8ft are the maximum seas in which these units can jack out of the water. If the hull should roll, pitch, and heave to an extent that the legs come into contact with the ocean bottom, particularly if it is hard, the legs can be severely damaged. The preload sequence is usually done in stages, with the hull never rising more than 5ft out of the water to safeguard against having a leg punch through. If the ocean bottom is soft and consists of clay, it is not uncommon to take 7 or more sequences, with each sequence taking 7 to 12 hours. The unit s pumps seawater into its preload tanks, adding weight to the hull and driving the legs. After the legs are driven and the hull goes into the water, the seawater is dumped overboard and the sequence is begun again. This process occurs until the legs no longer penetrate the ocean bottom. The concept is to load the legs to a level above that which the unit will encounter in the harshest predicted environment. The newer, enhanced premium units do a single preload in which the jacking system is strong enough to jack the unit with all the preload water onboard, the basic weight of the hull, and the full transit VDL. This is a significant advantage in that a much smaller weather window can be acceptable to move the unit. Jack ups are most susceptible to major damage or loss when they are floating. 2 Mat-type jack up unit The mat-type jack up also usually consists of three legs that are cylindrical and are from 8 to 12ft in diameter. The mat is carried just under the hull during mobilization, usually with 5ft gap. When the unit comes onto location, it jacks the mat down to the ocean bottom, and because of its low bearing pressure, usually under 500 to 600psf, unit jacks of the hull out of the water without going through the preload sequence required for independent-leg units. Their key advantages are that they were relatively inexpensive to build and leave no footprint at the drilling location. Unfortunately, the mat-type jack up unit also has several disadvantages : They are very susceptible to damage from any object on the ocean bottom. They tow very slowly because the mat and hull are large and create a lot of drag. Their mats are susceptible to being gouged by workboat propellers. Their upper hull has limited open deck storage space. Their legs sometimes form a wind-induced leg vibration known as vortex shedding at high winds, which can cause them to fail. [Fig-14] Typical jack up under operation (Source: DNV) 034 035

Vortex shedding is a form of severe vibration seen with smoke stacks without spoilers. Most mat rigs have cylinders for legs and are structurally limited to shallower water depths, usually less than 250 to 275ft. Only a few units have reached 300ft, and these units have lattice-type legs. For these reasons, mat jack ups have fallen into disfavor, although they are relatively inexpensive and for some well types are more than adequate. 2) Common factors that impact both types of jack ups Air gap, or the distance from mean water level to the bottom of the hull while the unit is jacked up in the operating condition, is a critical issue. The bottom of the hull must have a large enough air gap that the largest wave crest will not hit the hull and turn over the rig. Air gaps usually are 35 to 50 ft, with the larger air gaps in shallower water, because wave heights build as water depth decreases. If a unit should work over a platform with a very high deck, air gaps of up to 100ft are not uncommon; however, this obviously reduces the water depth rating. Jack up water depth ratings generally use minimal leg penetration of 15 to 25ft, which may not be the case in actual operation. Independent- and mat-leg jack ups also come in two types of drillfloor, slot and cantilevered. As previously discussed, slot units were initially built in the 1950 s through the late 1970 s; however, with bigger platforms, the ability to cantilever the drill floor over the platform had an advantage over the slot units, which could only swallow minimal-size platforms. As the cantilever moves out to position itself over a well, it generally loses combined drillfloor load rating. The combined loading consists of the hook, setback, rotary, and drive-pipe tension if that tension is hung off the drill floor substructure. Generally, a minimum cantilever length (~ 14 to 20 ft) is required for moving blowout preventers (BOPs) and other items next to the hull. Full rating is usually accomplished at center positions, but decreases as the cantilever moves further out and the drillfloor moves either side of center (usually ± 15ft). The rating on the extreme cantilever and extreme off-center can decrease by as much as 80%, leaving the unit capable of only light workovers. 3) Technological advances of jack up unit Unlike typical earlier 1-million-lbm cantilever load units, the new premium jack ups have ratings of at least 2 million lbm. With the advent of extended reach wells (ERWs), deeper gas wells, and high-pressure/high-temperature requirements, the higher load rating are required, so many older jack ups have been upgraded and enhanced, although not to the extent of some of the newer premium units built in the late 1990 s and early 2000 s. This unit has features : 2-million-lbm cantilever load rating 7,500psi-working-pressure mud system 70ft cantilever 400ft water depth rating 7,500kip VDL (which is typical of the dozen) V. Subsea Ongoing advances in subsea technologies and their proven application in offshore regions around the world mean that there can be few, if any, other areas of the upstream industry that can claim such strong prospects for the future. With exploration and development projects routinely taking place in waters well beyond 1500 m, and with some nearing the 3000 m mark, the need for reliable subsea systems and hardware - and continued essential R&D - remains paramount if oil and gas companies are to access the new and increasingly remote reservoirs they need to replenish their own reserves and meet the demands of an ever-thirsty global energy market. The future of the subsea market looks remarkably promising. The case looks even more solid when you consider that many observers appear to forget that subsea does not just mean deep water and harsh environments - there are dozens of developments currently under way or in the pipeline in much less than 400 m of water that will require subsea systems and hardware. When you consider that whatever the basic offshore design or concept - drilling rig, fixed production platform, floating production facility, or total seabed-to-shore package - subsea equipment of one form or another is required, the view gets even better. Add to this the increasingly cost-effective subsea systems also being introduced to the market or further refined, with various seabed processing, separation, boosting, and compression designs either in action or emerging for pioneering projects around the world within the next year or two, and the fundamentals become even more reassuring, not only for the industry itself but also for shareholders and an investment community looking for lower-risk options post-macondo. [Fig-15] Outline of subsea (Source: DNV) Accommodations for a crew of 120 036 037

1. Subsea production Arrangement optimization, operational availability and flow assurance of transported fluid during project lifetime are decisive factors to guarantee success and expected financial return from a huge investment characterized by an offshore system for oil & gas exploitation. Thus, the submarine system design comprises highly reliable sub-systems, equipment and related components. 1) Subsea production system 1 Pipes Pipes are widely employed for the transportation of the produced fluid. The pipes can be classified as rigid and flexible. Flowlines are those pipes subjected to static loading, since they are rested on the seabed, responding to installation, operation and pressure loads. Risers are used to connect the stationary production unit (SPU) to the flowlines along the water depth, therefore being subjected to dynamic loads [Fig-16] Pipe of subsea (Source: DNV) induced by waves and currents as well as installation and operational loads. Risers and flowlines may have either rigid or flexible pipes depending on the respective bending rigidity. Flexible pipes comprise several layers with polymeric and metal components and bending rigidity much smaller than that for rigid steel pipes. 2 Umbilical cable Umbilical cables are employed to control the subsea equipment remotely. [Fig-17] Umbilical (Source: DNV) They are able to transfer hydraulic pressure and electrical power to operate submerged equipment and valves as well as to retrieve data through electrical and/or optical fiber cables. Umbilical can also be used associated with additional hoses for well chemical injection. 3 Control system The control system is employed to control wells by opening and closing the valves installed on the X-trees and other subsea equipment. The hydraulic pressure generated at either the platform or the onshore terminal is sent through umbilical hoses to activate submarine valves. Hydraulic control system can be direct controlled or hydro-electric multiplex. 4 Wet christmas tree (X-Tree) It is the equipment installed at the wellhead to guarantee security barriers in case flow interruption is necessary, which assures reservoir natural pressure blockage. It comprises basically a set of valves, fail safe close, hydraulically operated through spring return to assure closing in case of hydraulic system depressurization. The valves operate through both direct and multiplex hydraulic control systems. 5 Manifold Subsea manifold is a set of tubes, valves and monitoring instruments assembled on a metal structure, interconnecting the drainage/flow of several wells to the production unit, thus reducing the number of lines that would be necessary. Manifold is not well safety equipment as the x-tree, [Fig-18] Pipe Line End Manifold - PLEM (Source: DNV) because it is considered as part of the pipe system it is connected, favoring the production flow in case of control system failure. Thus, the production blockage valves, operated hydraulically, are failed safe open. While the test blockage valves, operated hydraulically, are fail safe close. 6 Pipe line end manifold - PLEM The PLEM is a collector / distributor equipment, which [Fig-19] Pipe Line End Termination - PLET (Source: DNV) is characterized by the incoming or outgoing of more than two pipes. When used in the arrangement, it allows pipe sharing without operational flexibility. 7 Pipe line end termination - PLET The PLET makes it possible to connect, without divers, a rigid pipe and equipment to another pipe. It features a flange connection to be interconnected to the extremity of the rigid pipe, a blockage valve operated by ROV to allow pipe hydrostatic test, a HUB/MCV [Fig-20] Jumper (Source: DNV) for future connection to flexible riser or jumper. 8 Jumper Jumpers are used to accomplish connections between X-Trees, manifolds, PLEM and PLET. They can be presented as rigid or flexible pipes. 038 039