Jurnal Riset Energi HMTM "PATRA" ITB by patra research

Jurnal Riset Energi HMTM “PATRA” ITB

KATA PENGANTAR Puji dan syukur atas kehadirat Allah Swt. atas karunia-Nya yang dapat membuat kita dapat berhimpun dan memberikan manfaat bagi diri kita sendiri dan lingkungan. Kehadiran jurnal inipun tidak lepas dari usaha dan kerja keras divisi dan departemen terkait yang mewarnai perwujudan mimpi dari kepengurusan BP ‘Semarak’ yang akan berakhir. Himpunan Mahasiswa Teknik Perminyakan ‘PATRA’ ITB telah mewadahi anggota untuk dapat berkembang sesuai dengan tujuan dari didirikannya himpunan ini. Departemen Karya dan Divisi Riset Energi membantu untuk membawa realita dunia perminyakan yang penuh inovasi dan menuntut para praktisi untuk segera mencari solusi atas permasalahan yang ada. Di Indonesia sendiri, terdapat berbagai problematika lapangan yang kala dapat diupayakan penanganannya, mampu menciptakan asa akan produksi nasional demi memenuhi kebutuhan energi. Jurnal inipun diharapkan mampu membawa semangat untuk berkarya dan menumbuhkan karakter untuk kritis serta tanggap terhadap masalah yang ada, selain daripada keinginan untuk mencoba hal baru. Karya-karya yang adapun dapat menjadi inspirasi bahwa setiap orang bisa untuk melakukan hal serupa. Saya berharap bahwa jurnal ini menjadi pemantik untuk terus melakukan hal-hal nan bermanfaat. Hasrat untuk belajar tidak boleh pudar, hasrat untuk bermanfaat bagi sekitar juga harus tumbuh besar. -Untuk Patra yang lebih besar dan lebih kuat-122, PATRA!-

Bandung, 12 Februari 2019 Ketua Himpunan HMTM “PATRA” ITB Periode 2018/2019

Iqbal Ridalta Putra

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Jurnal Riset Energi HMTM “PATRA” ITB

DAFTAR ISI KATA PENGANTAR ............................................................................................ 2 DAFTAR ISI ........................................................................................................... 3 Pengaruh Penambahan Alkohol pada Injeksi Hydrolyzed Polyacrylamide (HPAM) .................................................................................................................. 4 Water Injection Design with Material Balance (MBAL) Software ...................... 14 Smart Completion Application for Sand Problem Mitigation .............................. 20 Highly Effective and Efficient Production Optimization using Combined Artificial Lift Sucker Rod Pump with Gas Lift .................................................................... 25 Utilisation of CO2 from Natuna Field for EOR and ECBMR in Central Sumatra Basin: A Hybrid Strategy to Increase Oil and Gas Recovery and to Decrease Global Warming .................................................................................................... 48

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Jurnal Riset Energi HMTM “PATRA” ITB

Pengaruh Penambahan Alkohol pada Injeksi Hydrolyzed Polyacrylamide (HPAM) Ganesha Gajah1,2, Patrick Ivan1,2, Mohammad Edwin Alif Utama1,2 dan Muhammad Hairul Fikri1,2 HMTM “PATRA” ITB, Institut Teknologi Bandung Petroleum Engineering Study Program, Institut Teknologi Bandung * 1

Abstract. Proses pemulihan reservoir merupakan hal yang kompleks dan biasanya memerlukan beberapa mekanisme fisik atau kimia. Injeksi Polimer sering digambarkan didominasi oleh satu mekanisme: viscosifikasi air mengurangi rasio mobilitas, dan menstabilkan bagian depan perpindahan untuk meningkatkan pemulihan minyak. Semakin banyak kontribusi mekanisme selain viscosifikasi air semakin dipahami. Dalam jurnal kali ini, akan dibahas mengenai pengaruh penambahan alkohol pada injeksi hydrolyzed polyacrylamide atau HPAM. Hasil dari percobaan didapat bahwa penambahan alcohol ini bersifat signifikan dalam mempengaruhi viskositas serta shear rate dari brine yang diuji. Hasil yang baik mungkin dihasilkan sebagian dari pengurangan tegangan antar muka dan sebagian sebagai hasil dari peningkatan viskositas fluida pemindahan. Keyword: alcohol, polimer, HPAM, viskositas, shear rate ©2018 HMTM “PATRA” ITB. All rights reserved.

1) Introduction HPAM (Hydrolyzed Polyacrylamide) merupakan suatu sintetik polymer yang banyak digunakan di Industri perminyakan dalam upaya meningkatkan perolehan hydrocarbon. HPAM banyak digunakan karena lebih murah. yang dibuat dengan cara menghidrolisis parsial PAM atau dengan copolymerisasi sodium acrykate dengan acrylamide. Lalu dalam percobaan yang ditulis dalam paper ini, HPAM yang digunakan merupakan HPAM yang sudah tersedia dan bukan buatan sendiri. Dengan cara diinjeksikan Bersama air dalam kadar tertentu, HPAM meningkatkan viskositas brine didalam reservoir sehingga menjadi lebih kental dan sukar untuk mengalir dibandingkan minyak ketika produksi dilakukan. Selain itu, hydrocarbon juga ikut terdorong oleh injeksi larutan ini. Laruan HPAM diinjeksikan dalam volume berbeda, bergantung pada volume hydrocarbon di reservoir sehingga apabila dibutuhkan injeksi yang cukup banyak, akan tidak cukup ruang bagi larutan ini direservoir yang merupakan salah satu masalah yang dihadapi. Oleh karena itu untuk mengatasi masalah ini, perlu ditambahkan alkohol kedalam larutan HPAM sehingga dapat mengurangi retensi polymer larutan ini. Dalam upaya mengurangi retensi polymer, alkohol direaksikan dengan alcohol sehingga jarak antar partikel HPAM lebih rapat. Jenis alcohol yang digunakan dalam paper ini adalah dari gugus ethanol.

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Jurnal Riset Energi HMTM “PATRA” ITB 2

Methodology

2.1

Pembuatan Core Buatan Metodologi pertama ialah pembuatan artifisial core dari camouran semen, pasir, dan air. Komposisi yang kami gunakan untuk pembuatan core buatan ini adalah 65 persen semen dan pasir serta 35 persen. Proses pembuatan dilakukan dengan mengaduk campuran semen, pasir, dan air pada suatu bejana dan dicetak melalui cetakan core yang berupa pipa pvc yang dipotong sesuai dengan ukuran core yang diinginkan.

Gambar 1. Hasil dari proses pembuatan artifisial core 2.2

Penentuan sifat fisik core Sifat – sifat fisikd ari core yang akan diuji adalah porositas Nilai dari porositas didapat dari hasil uji dengan PORG-200.

2.3

Penyamaan pH core dengan larutan KOH Penyamaan pH dilakukan dengan proses flooding secara static oleh KOH sehingga didapat nilai pH yang basa. Hal ini dilakukan dengan tujuan : 1. Kalibrasi pH dari core, agar nilai ph core dapat dipastikan dan tidak menganggu proses percobaan 2. Penyamaan pH juga bertujuan agar kondisi core buatan menyerupai kondisi core yang asli karena kondisi reservoir asli cenderung dalam keadaan basa. 3. Menghindari kondisi core yang bersifat asam karena dapat mengkorosi dan juga bereaksi dengan larutan HPAM dan Alkohol

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Jurnal Riset Energi HMTM “PATRA” ITB

Gambar 2. Penyamaan pH core 2.4

Uji Statik Uji static merupakan uji pendesakan core dengan alcohol. Uji static dilakukan dengan menggunakan statis yang menjadi penyangga larutan brine yang akan diuji. Uji static dilakukan selama 30 menit untuk mendesak core dengan larutan HPAM + Alkohol pada suhu 40oC. data yang diperoleh dari uji static ini adalah : 1. Penambahan massa core (massa akhir core-massa core sebelum uji static ) 2. Perubahan pH larutan selama Uji Statik

Gambar 3. Uji Statik

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Jurnal Riset Energi HMTM “PATRA” ITB 2.5

Uji Kompabilitas Langkah ini dilakukan untuk menguji kompabilitas dari larutan HPAM + Alkohol yang konsentrasinya divariasikan terhadap variasi dari larutan brine. Hasil dari uji kompatibilitas ini adalah : 1. Densitas Akhir 2. Ph Meter 3. Data Kualitatif (seperti terbentuk adanya gumpalan atau tidak) Pada uju kompatibilitas ini larutan dibagi menjadi 3 bagian yakni :

Gambar 4. Uji Kompatibilitas 2.6

Uji Rheologi dengan Fann VG meter Uji Rheologi dilakukan untuk menilai pengaruh dari konsentrasi terhadap viskositas dari larutan. Viskositas dari ketiga larutan akan diuji dengan Fann VG meter untuk mengetahui nilai viskositas akhir dengan penambahan alcohol pada larutan HPAM dan brine. Dari Uji Rheologi akan diambil data dari RPM serta dial reading lalu dianalisis sebagai fungsi shear rate dan shear stress serta shear rate dan viskositas larutan.

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Jurnal Riset Energi HMTM “PATRA” ITB

Gambar 5. Larutan-larutan yang akan diuji Rheologi 3

Result and Discussion

3.1

Hasil dari penyamaan pH Tabel 1. Penyamaan pH

Dari table 1, didapat hasil pH akhir yakni 13. Nilai densitas KOH yang tidak berubah secara signifikan menandakan bahwa KOH tidak bereaksi dengan core.

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Jurnal Riset Energi HMTM “PATRA” ITB 3.2

Hasil dari uji porositas Tabel 2. Uji porositas

Porositas yang didapat daru hasil uji porositas >15 persen, yang artinya porositas dari sampel artifisial core dalam kategori porositas yang baik. 3.3

Hasil dari Uji Statik Tabel 3.1 Data Core Uji Statik

Tabel 3.2 Data Larutan Uji Statik

Pada table 3.1, perubahan massa dari core sebelum dan setelah proses flooding secara static tidak berubah secara signifikan menandai bahwa tidak ada larutan yang bereaksi dengan core. Tidak adanya perubahan pH (pada table 3.2) menunjukkan bahwa larutan tidak bereaksi terhadap core maupun terhadap alkohol.

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Jurnal Riset Energi HMTM “PATRA” ITB 3.4

Hasil dari Uji Kompatibilitas Tabel 4.1 Densitas Uji Kompatibilitas

Tabel 4.2 pH hasil Uji Kompatibilitas

Pada table 4.1 menunjukkan bahwa penambahan alkohol tidak terlalu berdampak pada perubahan densitas sedangkan pada table 4.2 menandakan bahwa penambahan alkohol juga tidak berdampak pada perubahan nilai pH larutan. Hal ini menandakan bahwa penambahan alkohol tidak terlalu berdampak pada sifat larutan 3.5

Hasil dari uji Rheologi larutan Table 5.1 Pembacaan Dial Reading pada Fann – VG Meter

Hasil pembacaan Dial Reading pada Fann VG (Tabel 5.1) akan dilakukan analisis untuk mendapatkan nilai dari konstanta Bingham serta nilai viskositas plastic dari tiap larutan yang dapat dilihat pada table 5.2

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Jurnal Riset Energi HMTM “PATRA” ITB Table 5.2 Nilai Bingham yield point serta viskositas plastis tiap larutan

Hasil dari Tabel 5.1 dan 5.2 dapat dianalisis lebih lanjut dengan membuat grafik perbandingan antara shear stress dengan shear rate serta antara viskositas dengan shear rate agar didapat informasi lebih jauh sifat rheologi tiap larutan. Grafik 1. Shear Stress vs Shear rate tiap larutan

Grafik 2. Viskositas vs Shear Rate tiap larutan

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Jurnal Riset Energi HMTM “PATRA” ITB

Pada grafik 1 didapat bahwa dengan bertambahnya konsentrasi alkohol nilai dari shear stress semakin bertambah. Peningkatan dari shear stress menandai bahwa viskositas dari larutan ikut bertambah. Hal ini dibuktikkan pada grafik 2, penambahan konsentrasi alkohol menambah nilai viskositas pada larutan. 4

Conclusion Untuk menilai pengaruh dari alkohol terhadap injeksi Hydrolyzed Polyacrilamide maka diperlukan beberapa tahap eksperimen seperti pembuatan core, penyamaan pH, Uji sifat petrofisik, Uji static, uji kompatibilitas, dan uji rheologi dari larutan. Hasil dari Uji sifat petrofisik didapat bahwa kondisi porositas artifisial core baik. Sedangkan hasil dari Uji Kompatibilitas serta Uji Statik didapat bahwa penambahan alkohol tidak berdampak pada kondisi core atau kondisi dari HPAM, namun berdampak pada sifat rheologi dari larutan HPAM dan Alkohol. Hal ini membuktikan bahwa penambahan alkohol dapat menjadi alternatif untuk meningkatkan viskositas dari larutan HPAM dan Brine. Namun, perlu dilakukan studi lebh lanjut mengenai dampak penambahan alkohol pada larutan brine dan polimer jenis lain untuk mendapat hasil yang lebih memuaskan.

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Jurnal Riset Energi HMTM “PATRA” ITB References Regina, Asha. 2014. Rate Optimization of Surfactant Flooding for 5-Spot Pattern in Tempino Field.MSc Thesis. Petroleum Engineering Study Program, Institut Teknologi Bandung, Bandung, Indonesia. Al-Adasani, A and Bai, B. 2010. Recent Developments and Updated Screening Criteria of Enhanced Oil Recovery Techniques. Paper SPE-130726-MS. Presented at International Oil and Gas Conference and Exhibition in China, 8-10 June, Beijing, China. doi:10.2118/130726-MS Austad T, Fjelde I, Veggeland K and Taugbøl K. 1994. PhysicochemicalPrinciples of Low Tension Polymer Flood. J Petrol Sci Eng10:255–269. doi:10.1016/0920-4105(94)90085-X SPE-179672-MS: Tagavifar, Mohsen et al. 2016. Measurement of Microemulsion Viscosity and Its Implications for Chemical EOR. The University of Texas

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Jurnal Riset Energi HMTM “PATRA” ITB

Water Injection Design with Material Balance (MBAL) Software Pransiska Marlina1,2, Hidayat Handarianto1,2 dan Ahnaf Fairuz Gibran1,2 HMTM “PATRA” ITB, Institut Teknologi Bandung Petroleum Engineering Study Program, Institut Teknologi Bandung 1

Abstract. Indonesia merupakan salah satu penghasil minyak di dunia. beberapa sumur di Indonesia bahkan telah diekplorasi sejak zaman Belanda dan masih berproduksi hingga sekarang. Setelah puluhan bahkan ratusan tahun berproduksi, sumur akan mengalami penurunan laju produksi. Oleh karena itu, perlu dilakukan Second recovery yaitu waterflood. ©2018 HMTM “PATRA” ITB. All rights reserved.

Introduction

Waterflood adalah salahsatu metode secondary recovery dimana air di injeksikan ke dalam reservoir dengan tujuan untuk mendesak residual oil yang terdapat di dalam reservoir sehingga dapat diproduksi kembali. Secondary recovery perlu dilakukan karena sumur sudah tidak dapat berproduksi secara natural dengan mengandalkan natural flow. Sehingga perlu digunakan bantuan dengan system waterflood Secondary recovery dengan waterflood yaitu dilakukan dengan menginjeksikan air kedalam reservoir oil melalui beberapa sumur injeksi di sekitar lapangan. Fungsi air yang di injeksikan kedalam reservoir berguna untuk mendesak oil kearah sumur produksi sehingga oil dapat di produksi. Air yang digunakan untuk waterflood biasanya adalah brine. Injection well dapat berasal dari production well (production well yang digunakan sebagai injection well) atau sumur yang dibor dengan tujuan spesifik yaitu untuk digunakan sebagai injection well.

Methodology

2.1

Methodology A Waterflood memiliki mekanisme kerjanya dengan menginjeksikan air ke dalam formasi yang berfungsi untuk mendesak minyak menuju sumur produksi (produser) sehingga akan meningkatkan produksi minyak ataupun dapat juga berfungsi untuk memper-tahankan tekanan reservoir (pressure maintenance). Keuntungan menggunakan waterflood :  Mobilitas yang cukup rendah Air mudah didapatkan  Pengadaan air cukup murah

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Jurnal Riset Energi HMTM “PATRA” ITB   

2.2

Berat kolom air dalam sumur injeksi turut memberikan tekanan, sehingga cukup banyak mengurangi tekanan injeksi yang perlu diberikan di permukaan Mudah tersebar ke daerah reservoir, sehingga efisiensi penyapuannya cukup tinggi Memiliki efisiensi pendesakan yang sangat baik Result and Discussion

Result

2.2.1

Figure 1. History Matching without water influx

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Jurnal Riset Energi HMTM “PATRA” ITB

2.2.2

Figure 2. History matching with water influx

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Jurnal Riset Energi HMTM “PATRA” ITB 2.2.3 Recovery Factor without Water Injection

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Jurnal Riset Energi HMTM “PATRA” ITB 2.2.4 Recovery Factor with Water Injection

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Jurnal Riset Energi HMTM â&#x20AC;&#x153;PATRAâ&#x20AC;? ITB 3

Conclusion

Dilihat dari data Recovery Factor selama 10 tahun, water injection dapat meningkatkan nilai Recovery Factor sebesar 1.903%

Nomenclature : Fluid velocity [m/s] đ?&#x2018;&#x192; : Viscosity [Paâ&#x2C6;&#x2122;s] đ?&#x2018;Ľ : Interfacial tension [mN/m] đ?&#x2018;Ą : Water relative permeability [ ] đ?&#x203A;ź References Regina, Asha. 2014. Rate Optimization of Surfactant Flooding for 5-Spot Pattern in Tempino Field.MSc Thesis. Petroleum Engineering Study Program, Institut Teknologi Bandung, Bandung, Indonesia. Al-Adasani, A and Bai, B. 2010. Recent Developments and Updated Screening Criteria of Enhanced Oil Recovery Techniques. Paper SPE-130726-MS. Presented at International Oil and Gas Conference and Exhibition in China, 8-10 June, Beijing, China. doi:10.2118/130726-MS Austad T, Fjelde I, Veggeland K and TaugbĂ¸l K. 1994. PhysicochemicalPrinciples of Low Tension Polymer Flood. J Petrol Sci Eng10:255â&#x20AC;&#x201C;269. doi:10.1016/09204105(94)90085-X

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Jurnal Riset Energi HMTM “PATRA” ITB

Smart Completion Application for Sand Problem Mitigation Herianto1,2, Jihaan Aliyyah Widagdo1,2 dan Johan Iswara Lumban Tungkup1,2 HMTM “PATRA” ITB, Institut Teknologi Bandung Petroleum Engineering Study Program, Institut Teknologi Bandung 1

Abstrak. Masalah kepasiran adalah masalah yang umum dijumpai dalam lapangan perminyakan, khususnya lapangan yang sudah tua atau memiliki formasi yang tidak terkompaksi dengan baik. Masalah ini ditandai dengan terproduksinya pasir bersamaan dengan hidrokarbon. Selain diakibatkan oleh kondisi reservoir itu sendiri, masalah kepasiran dapat juga dipicu oleh laju alir produksi yang melebihi laju alir kritis. Dampaknya, formasi dapat tererosi dan pasir akan terproduksi. Pasir yang terproduksi ini adalah hal yang tidak diinginkan karena akan menjadi limbah dan dapat menimbulkan banyak kerugian. Misalnya, pasir dapat meningkatkan gesekan yang terjadi di sepanjang pipa produksi atau membentuk scale. Sebagai Tambahan, produksi pasir yang berlebih ini akan membutuhkan biaya untuk penanganannya agar tidak merusak fasilitas permukaan, seperti separator. Salah satu cara yang dapat kita lakukan untuk menangani masalah kepasiran (sand control) adalah dengan smart completion. Smart completion masih jarang digunakan sebagai solusi untuk menanggulangi masalah kepasiran, khususnya untuk sumur-sumur dangkal. Penggunaan smart completion, seperti ICD (Inflow Control Device), dapat meningkatkan umur sumur dengan menurunkan distribusi tekanan yang tidak beraturan di beberapa lapisan sumur dan dengan demikian akan mengurangi masalah kepasiran. Dalam jurnal ini, tim kami akan menggunakan ICD untuk membuktikan bahwa masalah kepasiran dapat dikurangi dengan mengatur laju alir produksi hidrokarbon. Kata kunci: masalah kepasiran, sand control, smart completion, ICD, laju alir ©2018 HMTM “PATRA” ITB. All rights reserved.

Latar Belakang

Produksi pasir yang berlebihan dapat menyebabkan kerugian pada perusahaan seperti scaling, erosi pada dinding pipa, dan beberapa kerusakan pada fasilitas produksi di permukaan. Pencegahan masalah kepasiran konvensional umumnya dengan dengan gravel pack dan kimia, dimana masih tergolong mahal secara ekonomi dan menimbulkan kerugian lain, seperti reduksi permeabilitas. Metode gravel pack memang popular untuk digunakan sebagai metode penanganan pasir. Namun, biaya yang perlu dikeluarkan perusahaan untuk pemasangan dan pengawasan cukup mahal. Metode penanganan pasir menggunakan metode kimia menimbulkan dilemma bagi perusahaan. Di satu sisi, metode ini berhasil mengurangi produksi pasir yang berlebihan karena dapat memperbaiki lapisan batuan yang belum terkompaksi dengan baik. Di sisi

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Jurnal Riset Energi HMTM “PATRA” ITB lain, metode kimia menyebabkan reduksi permeabilitas yang cukup signifikan. Ini dikarenakan semakin kompak suatu batuan, pori-pori akan semakin kecil atau bisa saja pori menjaid terisolasi. Jika hal ini tidak ditangani dengan baik, produksi hidrokarbon dapat menurun dan menimbukan kerugian bagi perusahaan. Oleh karena itu, masih kurangnya minat terhadap metode smart completion membuat tim kami tertarik untuk meneliti metode ini lebih lanjut dan menganalisis apakah metode ini dapat efektif untuk menangani masalah kepasiran.

Teori Dasar

Sand problem atau yang umumnya disebut dengan masalah kepasiran adalah kondisi dimana ikut terproduksinya pasir bersama fluida produksi hingga ke permukaan. Faktor yang menyebabkan masalah kepasiran ini salah satunya adalah formasi yang kurang terkonsolidasi sehingga kurang eratnya antar partikel yang menyebabkan pasir dapat secara mudah ikut dalam aliran. Selain itu, laju alir yang terlalu tinggi dapat meningkatkan presentase pasir terbawa fluida. Masalah kepasiran dapat menyebabkan beberapa masalah seperti scaling dan erosi pada pipa, dimana hal ini dapat menyebabkan kebocoran pada pipa. Pasir yang terproduksi juga dapat terkumpul lalu menumpuk dalam fasilitas produksi di permukaan. Hal ini membuat beberapa penanganan tambahan seperti pasir yang terkumpul pada separator harus dilakukan, misalnya pembersihan berkala untuk membersihkan separator dari pasir. Tentunya, hal ini menyebabkan penambahan biaya produksi serta minimnya penanganan lanjutan limbah pasir yang dihasilkan. Pada sumur dengan tekanan rendah seperti sumur yang sudah lama diproduksi atau sudah mengalami penurunan produksi, biasanya masalah kepasirannya akan diabaikan atau kurang ditangani karena dengan metode konvensional seperti gravel pack memiliki biaya operasional dan perawatan yang mahal serta metode kimia yang kadang tidak dapat diandalkan dalam penggunaan jangka panjang. Pada umumnya, masalah yang menyebabkan sand problem, yaitu laju alir yang terlalu tinggi sehingga menyebabkan pasir dari dinding formasi ikut terproduksi. Dampak tersebut dapat dikurangi dengan penggunaan metode smart completion, contohnya penggunaan ICD ( Inflow Control Device). Metode ini dilakukan dengan mengatur laju alir sehingga laju alir tersebut tidak melewati critical rate, yaitu laju dimana pasir akan mulai terproduksi

Metode Pada riset kami, kami menggunakan simulasi dengan menggunakan software

REVEAL dimana software ini dapat menunjukan pengaruh tekanan laju alir dasar sumur terhadap produksi pasir. Data yang digunakan : Initial Pressure = 5514.696 psia Depth = 7500 ft

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Jurnal Riset Energi HMTM “PATRA” ITB Temperature = 170 oF Start date = 01/01/2000 End date = 01/01/2006 Tabel 1. Pwf untuk masing-masing case Case

Pwf (psia)

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

Langkah kerja dalam penyelesaian masalah tersebut yaitu membuat sensitivitas pwf untuk melihat presentase produksi pasir yang mungkin terjasdi dengan menggunakan data Pwf yang ada.

Gamabar 1. Grafik sensitivitas jumlah pasir yang terproduksi untuk Pwf tertentu

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Jurnal Riset Energi HMTM “PATRA” ITB

Gambar 2. Grafik sensitivitas kumulatif pasir yang terproduksi untuk pwf tertentu 4

Analisis

Semakin besar perbedaan tekanan, semakin cepat produksi pasir terjadi dengan laju yang besar pula. Dalam kasus ini, kami mengasumsikan reservoir terbatas (kecil/ multiwell). Dengan hasil dari beberapa kasus yang kami uji, kami menemukan bahwa akan ada suatu nilai titik tekanan alir dasar sumur (Pwf) tertentu di mana kumulatif produksi pasir akan menurun karena di awal produksi, jumlah produksi pasir sudah besar. Demikian, kita dapat menyimpulkan adanya batas minimum Pwf supaya keseluruhan sistem tubing, choke, fasilitas permukaan dan lainnya tidak rusak karena masalah kepasiran. Titik batas minimum tekanan alir dasar sumur ini bisa dijadikan sebagai dasar desain surface facility dan pipeline. Pemakaian ICD akan mempertahankan distribusi aliran yang baik pada sumur sehingga mengurangi kemungkinan terjadinya kepasiran yang terlalu cepat. Perlu diperhatikan, tekanan tetap perlu disesuaikan karena ICD bisa saja tersumbat oleh pasir jika laju produksi pasir sangat besar 5 1. 2. 3. 6

Kesimpulan Pada Pwf di bawah 1500 psig, terlihat bahwa laju produksi pasir menurun setelah beberapa waktu karena laju produksi pasir di awal sudah terlalu besar. Semakin besar perbedaan tekanan antara tekanan reservoir dan tekanan alir dasar sumur, produksi pasir semakin besar Pemakaian ICD dapat membantu mengurangi masalah kepasiran Rencana Pengembangan

Melakukan sensitivitas terhadap parameter lain, selain Pwf. Dalam hal ini, kita dapat melakukan sensitivitas terhadap permeabilitas reservoir atau saturasi.

Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 23

Jurnal Riset Energi HMTM “PATRA” ITB Referensi Guo, Boyun et al. 2007. Petroleum Production Engineering. Elsevier Books. Tulsa,OK. Khalid, M.A. 2014. Inflow Performance Relationship for Horizontal Wells Producing from Multilayered Heterogeneous Reservoir. OTC 24757. Qasem,F. et al. 2012. Modeling Inflow Performance for Wells Producing from Multilayered Solution Gas Drive Wells. SPE 149858

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Jurnal Riset Energi HMTM “PATRA” ITB

Highly Effective and Efficient Production Optimization using Combined Artificial Lift Sucker Rod Pump with Gas Lift Dicky Putra A., Bandung Institute of Technology, dialviansyah98@gmail.com, 087821458539

Abstract As production rate decreases and becomes uneconomically produced naturally, artificial lift is applied to proceed the production of a well. Because there is no ‘onefor-all’ artificial lift, its selection must be thoroughly analyzed based on specific well conditions which yields the one ultimate artificial lift that will perform best and give the most economic operating condition. Yet, some artificial lifts require high cost for both its expenditures. Innovative solution is required to optimize the production and fulfil future energy demand, one of which is application of “combined artificial lift”. Combined system considers two parts, i.e. primary and secondary system, in this case, SRP and Gas lift respectively. Although combined system design is more complex than regular system design, we can use nodal analysis approach to determine the most optimum design of both systems which leads to better production operation. During its design process, economic aspect has to keep on being evaluated to ensure that combined system can perform better than regular system economically. Due to having wider operating range, combined artificial lift application can overcome limitations of single artificial lift, thus can be applied in a wider field condition. Combined system can produce at higher flowrate by using the same SRP or even smaller SRP due to gas lift effect compared to regular SRP system. Gas lift reduces required power (82%), PPRL (34%) and peak torque (44%) of SRP. At proper condition, combined system leads to higher revenue, i.e. US$403 million for SRP-GL, compared to US$310 million and US$216 million for regular SRP and GL respectively. Gas lift can also perform as back-up system so that production downtime reduction can be achieved because when primary system fails, gas lift can proceed production until SRP gets back into the operation which will surely lessen revenue loss decrement. In addition, gas lift can also be used to unload and stabilize well on a combined-system well, especially after workover is conducted, and thus prolong the life of primary system and lessen maintenance cost. Along with technological advancement, combined artificial lift is a very innovative and novel method to proceed production in a better operation. It can be the best solution to optimize production using the existing technologies before considering Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 25

Jurnal Riset Energi HMTM “PATRA” ITB EOR. This method has never been applied in Indonesia, but there are some cases where combined system application is proved to be a big success, such as in Xianjin, Balcon, and Tello fields. Introduction Along with production, reservoir pressure will decrease, unless there is a strong pressure-support from aquifer, which lead to production rate decreases and eventually lead to revenue decrement. In addition, as more explorations go on deeper layers, the number of production operation from deeper reservoirs increases, and energy of reservoir during production will be depleted, the best artificial lift is then to be selected, based on specific operating condition of well, to overcome inability of well to lift reservoir fluid naturally to the surface and proceed the production, even with higher flowrate in order to increase revenue. Nevertheless, with increasing lifting height, application of single lifting method becomes less efficient and less economic. For instance, SRP can only operate at low flowrate at deeper layers compared to shallower due to more loadings on pump plunger during fluid lifting which lead to lower revenue. The deeper well, the more cost it will take, which will worsen the total revenue. Gas lift operation also requires higher surface injection gas pressure, more gas injection rate, and higher investment in equipment. In addition, efficiency of gas lift system declines significantly because of liquid slippage problems. In some cases, single lifting application faces some problems related to satisfying production requirements. As alternative solution, combination of two artificial lifts which is applied in the same well simultaneously, can be utilized to optimize production and solve problems faced by single lift. The concept of combined artificial lift divides the system into two: Primary and Secondary system[1]. There are many combinations of artificial lifts, in this paper, it will be presented combination of SRP with Gas Lift, where SRP will perform as primary system and Gas Lift as secondary system. Sucker Rod Pump Effects as Primary System in Combined System SRP, as primary system, provides additional energy using periodical pumping in upstroke-downstroke motion of SRP yet not as high as single SRP does due to gas injection. The strength of SRP is best defined by fatigue endurance limit because most sucker-rod breaks are fatigue failures which occur at stresses well below the ultimate tensile strength, or even yield strength[5]. Gas Lift Effects as Secondary System in Combined System Besides reducing fluid density, Gas Lift can perform as Back-up system. If the primary system fails, which can result in several days downtime depends on rig availability to service the SRP equipment and well location, Gas Lift can carry out production with lower production rate. This important role can lessen revenue loss Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 26

Jurnal Riset Energi HMTM “PATRA” ITB during production downtime. However, Gas Lift injection valve should be installed below pumping fluid level. Gas Lift can also be used when unloading and stabilizing well production in combined system. This effect will be significant for wells producing sand or gassy oil wells that is loaded with heavy kill fluid. For sandy wells, SRP will last longer if it is not operated to clean-up a sandy well. Instead, the wells initially produce through the pump by Gas Lift until sand production decreases and stabilizes thus avoiding sand induced wear of the pump. For wells with heavy kill fluid loading, horsepower requirement will be several times greater than stabilized conditions with gassy fluid production. Instead of operating pump, it will be more effective and efficient to use Gas Lift during unloading and cleaning up the well after the workover. In addition, application of Gas Lift could decrease internal tubing corrosion by reducing the partial pressure of corrosive gases by decreasing the pump discharge pressure due to lighter oil column density[1]. Gas Lift effects on primary system when designing combined system are presented in Appendix. Combined System Operation Condition In high PI and high reservoir pressure wells, a packer is not required to be installed if there is proper spacing between pump intake to the injection valve. The fluid level in the casing annulus should remain above the pump intake over the full range of production[2]. By installing pump several hundred feet below the injection valve, injection of gas lift will not push the pumping fluid level to the depth of pump intake. Nevertheless, if the pump is designed to be installed near injection valve, packer is however required to prevent unexpected increase in gas injection pressure which can depress pumping fluid level down to pump intake depth. In high PI and low reservoir pressure wells, a packer is usually required when pump intake pressure does not exceed the operating injection gas pressure at pump intake depth to prevent lift gas from entering pump. Methodology Methodology and modeling workflow are listed below. Flowchart is also presented below. 1. Obtain/gather and/or calculate data required to design each regular system, i.e. well data, production data, PVT data, reservoir characteristics, and data related to artificial lift method. 2. Construct IPR and TPR based on each well’s condition to determine well deliverability and determine desired flowrate based on AOFP. 3. Design regular system, i.e SRP and Gas Lift, based on desired flowrate. 4. Design the combined system based on design results of both regular systems.

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Jurnal Riset Energi HMTM “PATRA” ITB 5. Conduct economic analysis to evaluate the design of combined system due to its complexity and wider operating range. 6. Re-design the combined system for case of smaller pump to produce at the same desired flowrate, and/or for case of increasing flowrate using the same pump if necessary.

Design Principle The design of combined system is more complex than that of regular system, because we must ensure the best condition is achieved, both operational and economics. However, we can approach the design using nodal analysis by taking the solution node at bottom hole. By using nodal analysis, we can also conduct sensitivity analysis on each variable parameter to understand its effects on the design until we obtain the most optimum design.

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Jurnal Riset Energi HMTM “PATRA” ITB System Analysis and Result Here is shown the typical well schematic diagram of well D-1 and its data.

Parameter Depth of perforation Casing size OD, ID Tubing size OD, ID Wellhead Temperature Wellhead Pressure Reservoir Pressure Production GLR Productivity Index Water Cut Oil SG Formation Water SG Reservoir Temperature Gas SG Injection Depth SRP Type Plunger diameter Rods diameter Pump Setting Depth

Type of Data

Well Characteristics

Reservoir and Production Characteristics

Gas Lift

Sucker Rod Pump

Value 7,000 6 5/8; 6.049 3.5; 2.75

Unit Ft In In

120

100 1,800 50 0.9 90 0.86 1.05

psig psig scf/stb Bbl/day/psi % -

180

0.65 6,500 Ft C-1280-365-192 (base SRP) 2.5 In 7/8; 3/4; 5/8 In 6,500 ft

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Jurnal Riset Energi HMTM “PATRA” ITB

R, P, A, C

53; 172.5; 210; 120 Table 1 - Main Data of SRP-GL

Firstly, we design each scenario, i.e. Regular SRP operation, Regular Gas Lift operation, and Combined SRP-GL operation, thus we can also compare which scenario would perform best when applying in well D-1 both engineering and economic aspect. Figure 2 - IPR & TPR curve of well D-1 There is no natural flowing scenario because IPR and TPR curves do not intersect each other as shown in Figure 2. Sensitivity of each design parameter will be attached in Appendix to ensure the most optimum operation is achieved. A. Regular Sucker Rod Pump Operation We firstly need to provide requirement data as listed in Table 1. And the calculation of operating parameters related to SRP production operation, such as maximum pumping speed (Nmax), PPRL, peak torque (T), maximum deliverability (Qmax), and prime mover power (Ppm), especially to ensure that selected SRP type can operate at our desired rate. Here is tabulated of parameter constraints compared to design operation of SRP C-1280D-365192. Parameter Maximum Design Unit Constraints Limit Operation 16.5 15.5 SPM Nmax 1,028 680 Stb/day Qmax 36,500 30,534 Lbs PPRL 1,280,000 1,192,298 In.lbs Peak Torque Table 2 - Parameter constrains and design operation of SRP

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Jurnal Riset Energi HMTM “PATRA” ITB In addition, here is also tabulated the other parameters related to SRP design. Parameter Ph Pf Ppm Wf Wr

Value 50 20 95 11,540 11,203

Unit hp hp hp Lbs Lbs

Table 3 - Design parameters of SRP operation B. Regular Gas Lift Operation The amount of injection rate will be proportional to the liquid recovered until it reaches ‘Optimum Point’ and beyond that point, less liquid will be recovered along with additional gas injection. Here is presented the most optimum regular gas lift operation. Parameter Injected GLR Liquid recovered Injection pressure Actual HP compressor Injected gas rate

Value 1,450 643.5 723 60.27 0.933

Unit Scf/stb Stb/day psig HP MMSCFD

Table 4 - Design parameters of Gas Lift operation Sensitivity analysis on the other design parameters and gas lift valves design are presented in Appendix. C. Combined SRP-GL Operation In combined system design, it is difficult to operate where each system is at their most optimum points due to their different range of flowrate. The term of ‘GLR injected’ in combined system will yield higher amount of injected gas rate than Regular Gas Lift although it has the same value of GLR injected. Case I: SRP C-1280-356-192 + Gas Lift, Rate: 680 stb/day Here is the result of combined SRP-GL operation which gives the best operating condition. Parameter Value Unit 950 Scf/stb GLRinj 680 Stb/day QL,prod 760 psig Injection pressure 40.99 HP Actual HP compressor 6.95 hp Ph 20.33 hp Pf

Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 31

Jurnal Riset Energi HMTM “PATRA” ITB 36.821 3,167 22,159 803,957

Ppm Wf PPRL Peak Torque

hp Lbs Lbs In.lbs

Table 5 - Design parameters of Case I Sensitivity analysis on different design parameters is presented in Appendix. Case II: SRP C-1280-365-192 + Gas Lift, Rate: 952 stb/day As consequences of Gas Lift injection, flowrate can be increased more than normal or maximum flowrate that can be achieved by regular SRP operation. In this case, it is designed to increase the flowrate to 952 stb/day. Here is the result of combined SRP-GL operation after flowrate increase.

Parameter GLRinj QL,prod Injection pressure Actual HP compressor Ph Pf Ppm Wf PPRL Peak Torque

Value 950 952 760 57.39 6.95 20.33 36.82 3,167 22,159 803,957

Unit Scf/stb Stb/day psig HP hp hp hp Lbs Lbs In.lbs

Table 6 - Design parameters of Case II However, due to SRP operates at higher flowrate than normal operation of regular SRP, Gas Lift injection should not be interrupted during the production because it is very vital to keep lightening the fluid column inside the tubing at desired flowrate otherwise the SRP will bear overloading due to fluid column and put the whole production system in risks. On the other hand, it is still possible to carry out the production even though the SRP fails as mentioned earlier. Case III: SRP C-640-256-144 + Gas Lift, Rate: 952 stb/day Besides only increasing flowrate, we can also downsize the SRP and still producing at higher flowrate thus the capital expenditure of SRP will be lower thus a better production optimization can be achieved. Here is chosen

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Jurnal Riset Energi HMTM “PATRA” ITB the SRP C-640-256-144 to produce at 952 stb/day at 6500 ft PSD. Here is the design result. Parameter GLRinj QL,prod Injection pressure Actual HP compressor Ph Pf Ppm Wf PPRL Peak Torque

Value 950 952 760 57.39 6.95 16.27 31.35 3,167 19,687 551,151

Unit Scf/stb Stb/day psig HP hp hp hp Lbs Lbs In.lbs

Table 7 - Design parameters of Case III

Economic Evaluation Economic aspect is one of the most vital aspect to be evaluated in every project to be implemented. In fact, it is the driving force of all operations in industry. If a project is not economic or give little revenue with greatly higher efforts or costs, the operations will most likely not be executed even though it is engineeringly possible. Here are the economic aspects to be considered in economic evaluation. Parameter Oil price Gas price Compressor price Rod price Gas lift valve price SRP C-1280-365-192 price SRP C-640-265-144 price Power cost Electricity cost Insurance cost Personnel cost Maintenance cost Workover (regular system) cost Workover (combined system) cost

Value 78 3.1 15,000,000 1.35 – 1.45 2,000 60,000 40,000 2.15 0.12 10 3 5 1,000,000

Unit USD/bbl USD/MMbtu USD USD/ft USD USD USD USD/HP/day USD/kWh % of income USD/bpd USD/bpd USD

1,200,000

USD

Table 8 - Economic aspects to be considered Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 33

Jurnal Riset Energi HMTM “PATRA” ITB Sensitivity analysis is conducted on total number of wells, i.e. 5 wells, 10 wells, 15 wells, and 20 wells, then we can determine the Minimum Operating Wells (MOW), in which a minimum number of wells to be applied combined system thus we can get higher revenue compared to regular system in a certain production period, in this case a 20-year production. Here is tabulated the maximum daily revenue of each scenario. Production rate per well, stb/day/well 680 643.5 680 952 952

Scenario Regular SRP Regular Gas Lift Case I Combined Case II SRP-GL Case III

Highest revenue per well, USD/day/well 4,888 3,730 4,600 6,550 6,559

Table 9 - Maximum daily revenue comparison gas lift scenario has the lowest daily revenue per well due to its lowest production rate. From this case, it is clearly that we must increase the production rate when applying combined system, because if we produce at the same rate as regular, i.e. 680 stb/day, revenue from combined system would be lower as represented by Case I compared to regular system, especially SRP, which still has higher revenue. After increasing the flowrate, we can increase our revenue 143% up to 6,550 USD/day as shown by Case II. Using downsized SRP in combined system scenario for producing at higher flowrate also gives additional revenue as represented by Case III which obtains 6,559 USD/day. Difference of daily revenue for each scenario is affected by its own operational expenditure (OPEX). Here is presented the OPEX and CAPEX for each scenario. Scenario Regular SRP Regular Gas Lift Case I Case Combined II SRP-GL Case III

CAPEX, MMUSD 10 Wells 15 Wells 10.77 16.16 25.20 30.30 27.97 34.41

OPEX, USD/day 414 1,289 702

5 Wells 5.39 20.10 21.47

872

21.47

27.97

34.41

40.87

864

21.37

27.74

34.11

40.47

20 Wells 21.55 35.40 40.87

Table 10 - OPEX and CAPEX comparison Gas lift has the highest both OPEX and CAPEX due to compressor requirement and its daily horsepower cost. In addition, daily injected gas requirement, 10% of total injected gas, also gives additional OPEX for gas lift scenario. On the other hand, regular SRP scenario has the lowest both OPEX and CAPEX because SRP unit Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 34

Jurnal Riset Energi HMTM “PATRA” ITB price is relatively cheap. Nevertheless, Combined SRP-GL has lower OPEX compared to gas lift because it requires less compressor HP and prime mover HP. Automatically, CAPEX for combined SRP-GL is also higher because we require both SRP and Gas Lift. Mostly, this will lead to longer Pay Out Time (POT) compared to regular SRP. Here is presented the Net Present Value (NPV), Pay Out Time (POT), and Rate of Return (ROR) of each scenario for each number of wells and then we can determine the MOW for each case of combined SRP-GL, in a 20-year production. Scenario

Regular SRP

Regular Gas Lift

Combined SRP-GL: Case I

Combined SRP-GL: Case II

Combined SRP-GL: Case III

Economic Parameter NPV, MMUSD POT, year(s) ROR, % NPV, MMUSD POT, year(s) ROR, % NPV, MMUSD POT, year(s) ROR, % NPV, MMUSD POT, year(s) ROR, % NPV, MMUSD POT, year(s) ROR, %

Number of Well 10 15

77.61 155.22 232.84 310.45 0.66 18.13

0.66 18.13

41.64

99.79

157.93 216.08

3.68 15.60

2.15 16.77

1.70 17.17

1.47 17.37

55.00 126.51 163.23 269.52 3.10 16.02

1.90 16.98

1.84 17.04

1.37 17.46

88.33 193.16 297.99 402.82 2.08 16.83

1.31 17.51

1.06 17.74

0.93 17.86

77.61 155.22 232.84 403.86 2.07 16.84

1.30 17.53

1.05 17.75

0.92 17.87

Table 11 - Economic parameter comparison Due to having the lowest daily revenue, Gas Lift scenario also has the lowest both NPV and the longest POT. For SRP has relatively high NPV because of its lowest CAPEX and OPEX. Observing the results of three combined SRP-GL case, we can conclude that, apparently, Case I has the lowest NPV compared to the other scenario of combined SRP-GL because it produces the lowest rate which yields lowest revenue. Thus, it is apparent that we must re-design for the case of increased flowrate as presented by Case II. Based on both engineering and economic aspects, Case II can perform better and simultaneously gives higher NPV compared regular SRP for a 20-year production with MOW is 10 wells which are assumed to have Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 35

Jurnal Riset Energi HMTM “PATRA” ITB the same performance as Well D-1. Case III is conducted as the improvement scenario from Case II where besides increasing flowrate, we also use downsized SRP to lower CAPEX as shown in table 12. Case III results in slightly higher NPV, higher ROR, and lower POT compared to Case II. MOW of Case III is also 10 wells. Thus, the least number of wells to be applied combined system in a fieldscale development is 10 wells so that we would obtain higher revenue compared to regular systems. MOW depends on economic conditions, well productivity, reservoir capability, and many other factors, including from SRP itself as the primary system to lift the reservoir fluid. The better production profile, the less number of wells required to make combined system economically more beneficial. Combined SRP-GL would be more economic and applicable in field where gas is also produced from other wells thus there will be no need in purchasing lift gas for gas lift operation. It is also more beneficial in term of economics if there has been available compressor thus no need to purchase new compressor and will lessen the investment cost of combined SRP-GL system. Due to necessity for lift gas, it is also more applicable and economic if the nearby wells produce gas.

Further Studies and Development Combined system studies still have many things to improve and can be further developed in the future. With proper design method and good potential of reservoir, combined system can optimize the production hence increase the revenue. We can consider application of combined system in deviated wells, wells with sand problem, wells with dual string production in commingle production. It can also be considered using other type of SRP, such as Mark II or Air balanced SRP, and intermittent gas lift injection to minimize excessive requirement of lift gas. If production history data are available, production decline analysis can also be considered in order to predict better the future production performance. It is also highly recommended, especially in Indonesia, to start implementing combined system to support energy resilience to fulfil domestic necessity for energy. Recently, development of combined system is still not progressed nor widely applied due to some reasons related to economics, engineering, availability, and risks, such as: 1. Inadequate lift gas supply. 2. Company tends to sell the produced gas or flare the associated gas. 3. Higher stability risks and issues, because we really ensure uninterrupted gas lift operation, especially during gas transportation if the location of gas source is far. 4. Production target has been reached or exceeded only by applying one regular lift system, thus company does not consider combined system. Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 36

Jurnal Riset Energi HMTM “PATRA” ITB 5. Depleted mature oil field that cannot be suitable for any artificial lift This field has reached tertiary stage of production. 6. Wells produce very high gas cut due to gas coning or high GOR wells in which gas comes out of oil at pump suction because it is apparently not suitable. Nevertheless, some of those reasons can be overcome and solved to increase combined system implementation, such as: 1. If company is operating field producing both gas and oil, in later stage of development, especially when gas contract has ended, company can start considering combined system by using the produced gas thus less expenditure required. 2. Safety of combined system, especially during gas transportation, can be increased by applying technology such as SCADA to detect pressure distribution in gas pipeline. Thus, in case of leak or pipe collapse, quick handling can be provided. 3. Although production target has been exceeded, it is highly recommended to always increase the production thus increased revenue can be achieved and support energy resilience, especially when it is truly more economic and profitable. 4. Before applying EOR project, we can consider water flooding to maintain the reservoir pressure thus artificial lift, including combined system can still perform well. 5. High gas cut can be solved by applying packerless completion, thus free gas will not enter the pump at its suction. For High GOR wells, setting pump at proper depth, where gas has not come out of oil, can be a solution when applying combined system to prevent downhole pump problems related to gas existence. Conclusion 1. In proper field/well conditions, combined system has been proved to operate more effective and efficient and give higher revenue compared to Regular system. 2. Combined system has wider operating range and can overcome operation limitations of regular system. 3. Capital expenditure of primary system can be decreased due to lower specification requirement, such as lower HP requirement, lower PPRL, etc. 4. Combined system is highly applicable in high pressure and high productivity index reservoir, although other conditions are also considerably applicable.

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Jurnal Riset Energi HMTM “PATRA” ITB 5. Both gassy and heavy oil wells are suitable for combined system as long as dissolved gas does not come out of the oil at suction of pump. 6. High water cut wells face no problem in applying combined system because it can still perform well. 7. Problems related to sandy wells and wells loaded with heavy kill fluid can be overcome by initial production or unloading using gas lift to longer pump life. 8. Gas lift can perform as Back-up system so that revenue loss can be lessened during production downtime due to primary system failure. Acknowledgement The authors would like to thank Mrs. Silvya Dewi Rahmawati, S.Si., M.Si., Ph.D. for constantly guiding, supporting, and giving me advice related to the content of this paper, and Mr. Marda Vidrianto for giving me information especially in real industry operation.

Nomenclature Pwh = Wellhead pressure, psig Pwf = Flowing bottom hole pressure, psig Nmax = Maximum pumping speed, SPM GLRinj = Gas-liquid ratio injected, scf/stb Qmax = Maximum flowrate, stb/day QL,prod = Liquid production flowrate, stb/day Qinj = Lift gas injection flowrate, MMscf/day PPRL = Peak polished rod load, lbs Wf = Weight of fluid, lbs Wr = Weight of rod, lbs T = Torque, in.lbs Sp = Effective plunger stroke, in Dv = Depth of gas lift injection, ft PSD = Pump setting depth, ft

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Jurnal Riset Energi HMTM “PATRA” ITB Ph = Hydraulic power of SRP, hp Pf = Power to overcome friction, hp Ppm = Prime mover power, hp

References 1. Borja, H., and Castano, R.: “Production Optimization by Combined Artificial Lift Systems and Its Application in Two Colombian Fields”. 1999. SPE 53966 2. Zhao, R., Zhang, X., Liu, M., Su, L., Shan, H., Sun, C., Miao, G., Wang, Y., Shi, L., Zhang, M.: “Production Optimization and Application of Combined Artificial-Lift Systems in Deep Oil Wells”. 2016. SPE-184222-MS 3. G. Takacs, H. Belhaj.: “Latest Technological Advances in Rod Pumping Allow Achieving Efficiencies Higher Than With ESP Systems”. 2010. SPE136880-MS 4. Guo, B., William C. Lyonsm Ali Ghalambor. 2007. “Petroleum Production Engineering: A Computer-assisted Approach”. US : Gulf Professional Publishing 5. Clegg, Joe Dunn.: “High-Rate Artificial Lift”. 1998. Journal Petroleum of Technology

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Jurnal Riset Energi HMTM “PATRA” ITB Appendix 1. Combined SRP-GL System A. Sensitivity of Regular SRP Design - Variation in Pump Setting Depth PSD, ft

PPRL, lbs

T, in-lbs

Q, stb/d

6400

30052.80

1173563.63

1030.99

6500

30522.38

1191900.56

1027.62

6600

30991.95

1210237.49

1024.18

6700

31461.53

1228574.43

1020.69

6800

31931.10

1246911.36

1017.16

6900

32400.68

1265248.29

1013.57

- Variation in Pumping Speed at 6400 ft PSD N, SPM PPRL, lbs T, in-lbs 31340.65 1264936.93 16.559 30650.25 1215952.70 16 30052.80 1173563.63 15.5 29474.33 1132520.24 15

Dp, in 2.5 2.25 2 -

Q, stb/d 1137.39 1080.37 1030.99 983.11

Qmax, stb/d T, in-lbs 1172.77 1297172.02 1030.97 1173563.36 871.91 1062966.65 Variation in Plunger size at 6400 ft PSD and 15.5 SPM

Variation in Rod Type at 6400 ft PSD, 15.5 SPM, and 2.25 in Plunger Rod type Rd, in Qmax, stb/d T, in-lbs 1227.09 2093759.34 1.25 1145.23 1529712.32 Non-tapered 1 1075.62 1294692.73 0.875 1030.99 1173563.63 No. 75 Tapered 1035.48 1185721.98 No. 76

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Jurnal Riset Energi HMTM “PATRA” ITB

B. Sensitivity of Regular Gas Lift Design - Variation in Injection Depth and GLR injected on optimum liquid rate (stb/day) Injection Depth, ft GLRtot, scf/stb

4000

4500

5000

5500

6000

6500

1000 1500 2000 2500 3000 3500

109.30 126.80 140.10 152.60 162.70 171.00

207.00 227.40 242.60 255.00 265.50 274.50

310.80 333.30 348.90 361.30 371.60 380.40

413.10 438.90 455.60 467.90 477.50 485.40

513.40 542.50 560.30 572.70 581.80 588.80

611.00 643.50 662.50 674.90 683.50 689.50

Variation in Injection Depth and GLR injected on daily net (USD/day) Injection Depth, ft/ 4000 4500 5000 5500 6000 GLRtot, scf/stb 715.24 1353.62 2031.00 2697.72 3350.57 1000 802.17 1437.08 2104.19 2768.15 3418.31 1500 855.82 1479.86 2125.39 2771.72 3404.34 2000 898.90 1499.39 2120.75 2741.87 3350.55 2500 922.80 1502.53 2098.49 2690.97 3272.23 3000 932.32 1492.63 2063.17 2626.14 3177.93 3500

cash 6500 3985.06 4050.98 4020.32 3942.27 3836.81 3712.81

C. Sensitivity of Gas Lift Effects on SRP Design in Combined System - Gas Lift Effects on percent (%) decrement of PPRL of SRP Design Injection Depth, ft/ 4000 4500 5000 5500 6000 6500 GLRtot, scf/stb 14.96 16.84 18.71 20.54 22.29 23.93 1000 15.19 17.41 19.09 21.00 22.85 24.59 1500 15.37 17.33 19.33 21.29 23.19 24.98 2000 15.53 17.49 19.50 21.48 23.41 25.24 2500 15.66 17.63 19.64 21.63 23.57 25.42 3000 15.79 17.75 19.76 21.75 23.70 25.60 3500

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Jurnal Riset Energi HMTM “PATRA” ITB -

Gas Lift Effects on percent (%) decrement of Peak Torque of SRP

Injection Depth, ft GLRtot, scf/stb

4000

4500

5000

5500

6000

6500

1000

22.40

24.52

26.64

28.72

30.72

32.57

1500

22.75

25.35

27.17

29.37

31.49

33.47

2000

23.03

25.23

27.51

29.76

31.95

34.00

2500

23.26

25.46

27.76

30.04

32.26

34.35

3000

23.46

25.66

27.96

30.25

32.48

34.60

3500

23.65

25.83

28.12

30.41

32.65

34.84

Gas Lift Effects on percent (%) decrement of hydraulic power of SRP

Injection Depth, ft GLRtot, scf/stb

4000

4500

5000

5500

6000

6500

1000

81.75

79.79

78.36

77.21

76.25

75.35

1500

82.99

82.42

79.89

78.92

78.14

77.45

2000

83.97

82.04

80.86

79.96

79.26

78.68

2500

84.79

82.77

81.56

80.68

80.02

79.50

3000

85.51

83.40

82.13

81.22

80.56

80.08

3500

86.17

83.95

82.59

81.65

80.98

80.65

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Jurnal Riset Energi HMTM “PATRA” ITB D. Economic Evaluation Graphs - Combined SRP-GL: Case I

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Jurnal Riset Energi HMTM “PATRA” ITB -

Combined SRP-GL: Case II

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Jurnal Riset Energi HMTM “PATRA” ITB -

Combined SRP-GL: Case III

Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 45

Jurnal Riset Energi HMTM “PATRA” ITB E. Downsized SRP C-640-256-144 Design Result (After Gas Injection) Parameter Maximum Limit Design Operation Unit Constraints 17.82 14 SPM Nmax 975 952 Stb/day Qmax 25,600 19,686 Lbs PPRL 551,151 In.lbs Peak Torque 640,000 Parameter Value 6.95 Ph 16.27 Pf 31.35 Ppm 3,167 Wf 11,203 Wr F. Regular Gas Lift Design Valve Number 1 2 3 4 5 6 7 8 Operating Valve

Unit hp hp hp Lbs Lbs

Depth, ft 1,175 2,048 2,920 3,537 4,195 4,600 5,003 5,454 6,500

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Jurnal Riset Energi HMTM “PATRA” ITB G. Well Schematic Diagram

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Jurnal Riset Energi HMTM “PATRA” ITB

Utilisation of CO2 from Natuna Field for EOR and ECBMR in Central Sumatra Basin: A Hybrid Strategy to Increase Oil and Gas Recovery and to Decrease Global Warming 1

Dicky Putra A., dialviansyah98@gmail.com, 085747376868, Institut Teknologi Bandung 2 F. Khamim M., fajarkhamim6@gmail.com, 081320237847, Institut Teknologi Bandung Natuna Field is one of the major natural gas reserves in Indonesia which is located in Natuna sea. Natuna has 222 TSCF of gas deposit which is composed of 71% CO2, 28% CH4, 0.5% H2S, and 0.5% N2. Due to high CO2 content, we can inject CO2 for EOR and ECBMR in Central Sumatra Basin directly from Natuna Field. Thus, this strategy is expected to increase oil and gas recovery and decrease global warming. Central Sumatra basin is oil and CBM resources potential basin which has total unrecoverable resource about 13,210 Mbbl oil and 52.5 TSCF gas. Mixed gas is transported from Natuna to Central Sumatra using integrated pipeline system which has distance 782.173 miles, then injected into both oil and CBM reservoirs in Central Sumatra Basin. For increasing oil recovery factor, mixed gas injection method can maintain oil reservoir pressure so we can recover more oil. For CBM reservoir, not only to increase gas recovery factor, but also it can be a natural separator by absorbing CO2 to decrease global warming. Using CMGTM software simulation, we can calculate recovery factor for a certain period of time which are 30 and 50 years for oil and CBM fields in Central Sumatra respectively. If we consider the IGIP and IOIP are 12 MMSCF and 12.28 MMSTB, we can calculate gas recovery factor, i.e. 74.17% and 128.33% and oil recovery factor, i.e. 21% and 64%, before and after the injection. From observation, CBM reservoir without injection can only be produced until 28 years and the maximum gas recovery is 8.9 MMSCF. Meanwhile, we can still produce gas, even more than normal contract period which is assumed 50 years by mixed gas injection method. For oil reservoir, it would not be economic if we produced oil until the end of the contract, which is assumed 30 years, without mixed gas injection method because the maximum oil rate is 1.9 bbd. Nevertheless, it is surely different if we use mixed gas injection method, we can produce oil until the end of the contract because the maximum oil rate is still 200 bbd. From those results, it can be clearly stated that mixed gas injection method can increase oil and gas recovery and decrease global warming. Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 48

Jurnal Riset Energi HMTM “PATRA” ITB

This innovation is such longterm period method which is assumed to take 20 years to complete infrastructure development such as pipeline transportation and surface facilities both in Natuna Field and in Central Sumatra Basin. From the economic aspect, this project is expected to add more income to the company about US$ 369 million from EOR and about US$ 21.5 thousand from ECBMR, if oil and natural gas prices are US$ 69.87/bbl and US$ 3.2/MMBTU. Keywords: Natuna; Oil Reservoir; Coalbed Methane; Recovery Factor; Integrated Pipeline System

INTRODUCTION Indonesia holds proven oil reserves of 3.7 billion barrels with unrecoverable resource 28.54 billion barrels oil and is ranked in the top 20 of the world’s oil producers (Indonesia Energy Outlook 2016). However, declining oil production and increased oil consumption have resulted in Indonesia being a net oil importer since 2004. Today, oil and gas energy remains one of the economic pillars of Indonesian economy. Oil and gas energy provide significant income and provide the supply for domestic energy needs. While the energy demand is increasing, but oil and gas production in Indonesia is declining. In Indonesia, fossil fuel energy remains the primary energy source which is 65.6 % of total energy mix in 2014, and its contribution cannot easily be replaced by alternative and renewable energy sources. While fossil fuel energy contributes to global climate change through increased greenhouse gas emission. Nevertheless, Indonesia has a great unconventional hydrocarbon reserves, such as Coalbed Methane (CBM) which is about 453.3 TSCF. One of the CBM resources potential in Indonesia is Central Sumatra Basin which has a big gas resource which would yield 52.5 TSCF. Central Sumatra Basin also has a great oil resource potential which is about 13,210 Mbbl. But, there are big challenges in Central Sumatra Basin which are the depleted reservoir pressure and low both oil and gas recovery factor. Natuna Field Overview The Natuna Field is one of the major natural gas reserves in Indonesia with dry gas fluid reservoir type which is located in Natuna sea. The Natuna gas field lies approximately 140 miles northeast of Natuna Island and 680 miles north of Jakarta. The total volume of gas in the reservoir is estimated to be 222 TSCF, but it is composed of 71% CO2, 28% CH4 plus heavier hydrocarbons, 0.5% H2S, and 0.5% N2. The Natuna gas reservoir is interpreted to be an isolated, dome-shaped

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Jurnal Riset Energi HMTM “PATRA” ITB carbonate build-up structure (carbonate platform and reef complex) approximately 15 miles and 9 miles wide. Due to the high CO2 content, if we will produce a natural gas from Natuna for commercialization, its result is only about 75% which would yield 46 TSCF of recoverable hydrocarbon gas. So, it would be more reliable if we inject the mixed gas from Natuna Field to Central Sumatra Basin directly for Enhanced Oil Recovery (EOR) and Enhanced Coalbed Methane Recovery (ECBMR) (Doddy A., 2017). There are several methods or ways for reducing CO2 emission, such as injection of CO2 emissions into the depleted reservoir pressure called CO2 Flooding, continous CO2 gas injection, alternately CO2 gas with water injection or Water Alternate Gas (WAG) and Carbonate Water Injection (Green and Willhite., 1998). Global Warming Due to CO2 Carbon dioxide (CO2) is an important heat-trapping gas or greenhouse gas, which is released through many human activities such as burning fossil fuels and deforestation. CO2 concentration has increased about 30% during the last six decades to the level of 407.62 ppm in December 2017 and the trend keeps on increasing. The increment of CO2 concentration rises the global temperature to about 1.1 degrees Celsius since the late of 19th century which is driven largely by human activities. Oil and gas production activity which emits impurities such as CO2 also contributes to increase the global temperature, mostly by flare gas combustion. Nevertheless, the CO2 which is contained in the reservoir can actually be used to improve the recovery factor by maintaining reservoir using CO2 flooding method. EOR and ECBMR in Indonesia When a field is brought into a production phase, the reservoir fluid will flow naturally to the surface due to pressure difference between the reservoir and the surface in the primary stage or primary recovery. As reservoir pressure drops, an external fluid such as water or gas is injected into the reservoir through injection wells located in a site which has fluid communication with production wells. Both are used for the same purpose; maintain reservoir pressure. This stage is then called as secondary stage or secondary recovery. The fluid recovered in this stage still has the unchanged properties from the initial condition. The subsequent stage is called tertiary stage or tertiary recovery which is conducted in order to make some changes in reservoir and/or rock properties, such as reduce capillary forces, reduce residual oil saturation, reduce viscous forces, etc. to improve fluid reservoir recovery. With more than 650 oil fields which are 90% of those fields are categorized as mature field, Indonesia still holds a huge oil resources located onshore and offshore. Since the oil production of Indonesia has been declined between 5-20% per year to Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 50

Jurnal Riset Energi HMTM “PATRA” ITB the level of about 800,000 barrels oil per day, Indonesia needs to recover more oil to fulfil its oil consumption which is about 1,600,000 barrels oil per day. EOR and ECBMR is the solution that the government can proceed to recover more oil and gas. Both EOR and ECBMR have the same purpose, i.e. to improve fluid reservoir (in this context, oil for EOR and gas for ECBMR) recovery. Currently, there are still only a few EOR activities in Indonesia. The leading EOR method in Indonesia was steamflooding in Duri Field since 1985 which is the biggest steamflooding project in the world. The success of this project should become a trigger for conducting more EOR project in many depleted and mature oil field in Indonesia. In this paper, the authors would like to give a feasibility and opportunity of mixed gas from Natuna Field through pipeline transportation for EOR and ECBMR in Central Sumatra Basin. Automatically, this injection method could contribute the decreasing global warming by capturing and injecting this CO2, and also can maintain both oil and gas reservoir pressure, so the oil and gas recovery factor can increase significantly (Doddy A., 2017). Modelling Workflow The modelling workflow for this study can be described as shown in Fig. X. The modelling workflow consists of five steps: (1) Gather data, (2) Scale down parameters, (3) Process data using CMGTM Software Simulation, (4) Evaluate the results (IGIP, IOIP, Cumulative CBM production, and Cumulative oil production), and (5) Check the recovery factor. 1. Gather data Data gathered consist of reservoir and well geometry, petrophysical properties, and PVT data. 2. Scale down parameters This step is done by arranging the geometry of reservoir by taking the partition of the whole reservoir regions. 3. Process data using CMGTM Software Simulation Data are processed using CMGTM Software Simulation by inputting the required parameters such as cartesian grid model, reservoir properties, PVT data components, rock type, initial conditions, injection and production wells location, perforations and simulation timing. 4. Evaluate the results Results obtained from CMGTM Software Simulation such as IGIP, IOIP, cumulative CBM production, and cumulative oil production are evaluated based on engineering sense. 5. Check the recovery factor Compare the IGIP and IOIP with cumulative production. If the results indicate the increasing recovery factor, so the simulation model has succeeded. If the results do

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Jurnal Riset Energi HMTM “PATRA” ITB not indicate the increasing recovery factor, we have to re-check and go to the step (2) and go on.

METHODS Separation of Produced Natural Gas from Natuna During the first 20-year production, we proposed a method to produce natural gas from Natuna using slug catcher finger type on the sea bed. Its method to do this separation is by shifting he CO2 phase in the phase diagram from the gas phase to the liquid phase (Leksono M., 2016). This shifting requires certain pressures and temperatures that meet the temperature and pressure boundary to become liquid. This method is proposed for considering the ecomonic aspect too, during 20 years firstly while waiting the development and reconstruction of integrated pipeline system from Natuna field to Central Sumatra Basin. The natural gas that produce will be stored to gas buyer from Singapore using shipping method transportation. EOR Potential in Central Sumatra Basin This study is applied using reservoir properties data from X oil field in Central Sumatra basin. Due to the high of total unrecoverable resource in Central Sumatra basin, which is about 13,210 Mbbl oil, and a great proven Initial Oil in Place (IOIP) Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 52

Jurnal Riset Energi HMTM “PATRA” ITB by using CMGTM software simulation which is 12.28 MMSTB oil, so we have to optimize this potential. One of the ways to optimize this great potential is increasing the recovery factor by utilizing CO2 for EOR from Natuna field. In addition, for oil reservoir, it would be economic if we produced oil until the end of the contract with applying EOR, which is assumed 30 years. X oil field has dimension 2400 x 2400 x 80 ft, and using scale down principle, we can build a model in CMGTM software simulation which is 80 x 80 x 8. This sensitivity needs one production well (5850 ft - 5950 ft) with constraint Bottom Hole Pressure (BHP) 100 psi. On the other hand, it also needs one injection well (5950 ft – 6050 ft) with constraint BHP 4000 psi. In this paper, injection source will be provided from mix gas that earned from Natuna field. The mixed gas using 0.7 CH4 and 0.3 CO2 fraction, considering optimal recovery factor in this simulation. X oil field has some reservoir properties which are porosity based on petrophysical evaluation in average 22%, horizontal isotropic permeability 157 mD and vertical permeability 15.7 mD, Water Oil Contact (WOC) 5200 ft, reservoir pressure 2300 psia, reservoir temperature 170 F, Depth of the reservoir 5000 ft, and bubble point pressure (Pb) 1800 psia. Using CMGTM software simulation, we placed the production well in coordinate 40,40,1 and for injection well in coordinate 20,20,1, which have same well radius both production and injection well which is 0.25 ft. The input data for processing of this study are listed in Table 1 and Table 2. The location of X field in Central Sumatra can be seen in Figure 1. ECBMR Potential in Central Sumatra Basin In order to observe the effect of mixed gas injection on the improvement of CBM recovery, we use CMGTM Software Simulator to model our CBM reservoir. We take a partition from the whole CBM reservoir in size of 105 ft x 105 ft x 50 ft and model it as a cubical-shape reservoir in size of 21 x 21 x 1 grid as shown in Figure 2. In addition, we also have one production well with bottom-hole pressure constraint of 100 psi and flowrate constraint of 150 STB/day, and one injection well with bottom-hole pressure constraint of 1200 psi which are operated during 50-year CBM contract. Other parameter inputs are presented in the Table 3 and Table 4. We placed our production well in coordinate 11,11,1 and the injection well in coordinate 5,4,1 which both have well radius of 0.25 ft. By assuming the reservoir is isotropic, we can ensure that there is a connection between the production and injection well. Thus, the injection of mixed gas from the injection well will surely sweep the CBM towards the production well so more CBM will be recovered from the reservoir. Gas Flow in Pipes

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Jurnal Riset Energi HMTM â&#x20AC;&#x153;PATRAâ&#x20AC;? ITB In this paper, our innovation is such long-term period method which is assumed to take 20 years to complete infrastructure development such as pipeline transportation and surface facilities both in Natuna field and in Central Sumatra Basin. Integrated pipeline transportation system is the main value of transporting mixed gas from Natuna field to Central Sumatra Basin which has distance 400 miles. Piping design in production facilities involves the selection of a pipe diameter and a wall thickness that is capable of transporting gas from one piece of process equipment to another, even though sea bed likes from Natuna field to Central Sumatra basin, and within the allowable pressure drop and pressure rating restraints imposed by the process. We also consider the parameters that affect gas rate in pipes, basically is flow regimes. Flow regime describe the nature of fluid flow. These are two basic flow regimes for flow of a single-phase fluid: laminar flow and turbulent flow. Laminar flow is characterized by little mixing of the flowing fluid and a parabolic velocity profile. Then, turbulent flow involves complete mixing of the fluid and a more uniform velocity profile. Laminar flow has been shown by experiment to exist at Re < 2,000 and turbulent flow at Re > 4,000. Reynolds numbers between 2,000 and 4,000 are in a transition zone, and thus the flow may be either laminar or turbulent. In this case study, with assuming single-phase fluid and the mixed gas is flowing in the fully horizontal pipelines above sea bed, we can calculate the gas rate during transport mixed gas from Natuna field to Central Sumatra Basin. Reynold number equation for field units: đ?&#x2018;&#x2026;đ?&#x2018;&#x2019; = 1488

đ?&#x2018;&#x2026;đ?&#x2018;&#x2019; = 1488

4 12

(55.186)(15)( ) (0.01934)

đ?&#x153;&#x152;đ?&#x2018;Łđ??ˇ đ?&#x153;&#x2021;

= 21,229,774.56 (turbulent flow)

As many considerations for transporting mixed gas such as the distance, fluid properties, and turbulent flow, so we proposed to use Weymouth equation for calculating the gas rate in pipelines. According to Mohitpur et al. (2002) Weymouth equation overestimates the pressure drop calculation and because of that it is most frequently used in the design of distribution networks in spite of being less exact than other equations. For avoiding the trial and error procedure, thus Weymouth has proposed a function to calculate the transmission factor and its function is the result of pipe diameter function, which is: đ?&#x2018;&#x201C;=

0.032 1 đ??ˇ â &#x201E;3

0.01398 đ?&#x2018;&#x2018;

1â &#x201E; 3

Divisi Riset Energi â&#x20AC;&#x201C; Departemen Karya â&#x20AC;&#x201C; HMTM â&#x20AC;&#x153;PATRAâ&#x20AC;? ITB | 54

Jurnal Riset Energi HMTM â&#x20AC;&#x153;PATRAâ&#x20AC;? ITB This equation above is an empiric equation. Practically, this equation above is most frequently used in the gas transmission integrated pipelines system. Thus, Weymouth model is: đ?&#x2018;&#x2021;đ?&#x2018;? 1 0.5 đ?&#x2018;&#x192;12 â&#x2C6;&#x2019; đ?&#x2018;&#x192;22 đ?&#x2018;&#x17E; = 3.23 ( ) [ ] đ?&#x2018;&#x192;đ?&#x2018;? đ?&#x2018;&#x201C; đ?&#x203A;žđ?&#x2018;&#x201D; đ?&#x2018;&#x2021;đ??żđ?&#x2018;§Ě&#x2026;

0.5

đ??ˇ2.5

Integrated Pipeline System Mixed gas from Natuna field is transported to Central Sumatra using an integrated pipeline system as shown in Figure 9. We assume that the pipes are installed on the sea bed in a fully horizontal arrangement and neglect the pressure losses due to bending at the joints of pipes. Numbers in the Figure 9 shows the locations of compressors installed to give additional energy to push the mixed gas in nearby islands. First compressor is installed in the Natuna field Wellhead with discharge pressure 6000 psia to Mida Island. Second compressor is installed in Mida Island to transport the mixed gas to Siantan Island with discharge pressure 5000 psia. Third compressor is installed in Siantan Island to transport the mixed gas to Jemaja Island with discharge pressure is 5000 psia. Fourth compressor is installed in Jemaja Island to transport the mixed gas to Bintan Island with discharge pressure 6000 psia. Fifth compressor is installed in Bintan Island to transport mixed gas to Sumatra Island with discharge pressure 6000 psia. After reaching Sumatra, gas will be distributed to CBM and oil reservoir in a pipeline junction. Another compressor is installed to transport gas from the junction to CBM reservoir with discharge pressure 5500 psia. Meanwhile, no compressor needed to transfer gas from the junction to the oil reservoir because the pressure at the pipeline junction is still high enough to support the mixed gas transportation to the oil reservoir. The gas is transported with capacity of 16.293 MMSCFD with the total length of pipe is 782.173 miles. Based on the calculation using Weymouth correlation to model the pressure drop in pipeline system, the pressures in the wellhead of CBM and oil field are 1622.34 psia and 2025.33 psia respectively. Compressors installation data are presented in Table 7. Based on Table 7, the total HP compressor required is 6904.18 HP or 5.148 MW. Installation cost of compressor in range of 5 â&#x20AC;&#x201C; 15 MW is around US$ 0.5 â&#x20AC;&#x201C; 0.9 million/MW, so take the assumption of the cost USD per MW of compressor installation is US$ 0.8 Million/MW, we obtain the total cost of compressor installation is US$ 4,118,757.621. RESULTS Comparation of X Oil Field with and without injection In this study, there is a comparasion and sensitivity analysis for X oil field due to the reservoir pressure decline, so to improve the oil well performance, we proposed

Divisi Riset Energi â&#x20AC;&#x201C; Departemen Karya â&#x20AC;&#x201C; HMTM â&#x20AC;&#x153;PATRAâ&#x20AC;? ITB | 55

Jurnal Riset Energi HMTM “PATRA” ITB mixed gas injection from Natuna field. Thus, the oil recovery factor can be increased. From CMGTM software simulation, we obtained the Initial Oil In Place (IOIP) from X Oil Field, which is 12.278 MMSTB oil. From Figure 3, we also can calculate the oil recovery factor (RF) with and without injection for certain period which is 30 years based on oil company operator contract period. In this case, we assume the contract will start from 2038 until 2068, which are two sensitivity analysis with and without injection. If we simulate this X oil field without injection scenario, the result of cummulative oil production at the end of the contract which is 2068 only reach 2.58 MMSTB oil and maximum oil rate 1.93 bbl/day as shown in Figure 4. From these data, we obtain oil RF is about 21%. Considering the maximum oil rate 1.93 bbl/day, it is not economic to produce this field and it has been declining during 30 years. Nevertheless, it is surely different if we simulate this X oil field with mixed gas injection scenario from Natuna field, the result of cummulative oil production at the end of the contract is still good which is 7.86 MMSTB oil and the maximum oil rate still 200 bbl/day as shown in Figure 5. From these datas, surely we obtained oil RF about 64%. So, the second scenario with mixed gas injection is such a worthy scenario due to the increase of oil RF and the decline of oil rate production will be lower than without injection. Comparation CBM Reservoir with and without Injection By using CMGTM Software Simulator to model the effect of gas injection on the CBM recovery, it is can be seen clearly that the recovery factor of CBM will rise from 74.14% to 128.33% and the production period will last longer. By assuming the IGIP based on CMG is 12 MMSCF as shown in Figure 6, the longest period we can produce without injection is only about 28 years with maximum CBM recovery is 8.9 MMSCF, from 2038 until 2066. Meanwhile, we can keep on producing until even more than 50 years, from 2038 until 2088, if we produce the CBM reservoir with mixed gas injection as shown in Figure 7. The recovery factor exceeds 100% after mixed gas injection because mixed gas from Natuna field also contains CH4 which is also produced from the production well in CBM reservoir. Meanwhile, the CO2 will be absorbed by coal seam in the CBM reservoir. The coal seam acts as natural separator for mixed gas which contains 71% CO2, 28% CH4, 0.5% N2 and 0.5% H2S. This is such a great hybrid strategy where we can increase the recovery factor of CBM and decrease the global warming caused by CO2 simultaneously. The cumulative gas produced will be stagnant after 2066 which indicates there is no more CBM production rate as showed in Figure 8 for without injection scenario. Meanwhile, the CBM rate will keep constant if we inject the mixed gas into the CBM reservoir which then increases the recovery of CBM and longer the production period.

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Jurnal Riset Energi HMTM “PATRA” ITB Economics Evaluation The mixed gas injection scenario as we mention above is such longterm period method which is assumed to take 20 years to complete infrastructure development such as pipeline transportation and surface facilities both in Natuna field and in Central Sumatra Basin. During the longterm period, considering the economic side, we have to think how to utilize the natural gas from Natuna field. In this case, we proposed to produce gas from Natuna field using slug cathcer finger type. In the early production, there are many aspects that we have to consider it, which are injection well drilling; LNG project including upstream development cost, liquefaction, shipping, regasification; pipeline construction and slug catcher on the sea bed. All of these aspects will spend around US$ 306,000,000 with detail CAPEX around US$ 82,000,000 and OPEX around US$ 323,290 /day. The main project after shipping method during 20 years early production is injecting the mixed gas from Natuna field to Central Sumatra Basin for EOR 30 years and ECBMR 50 years based on projection. This project needs a big investation which are pipeline corrosion and compressor installation, with sub-total cost reach US$ 154,118,400. Nevertheless, its investation will be changed with the net profit from methane production through LNG project, EOR and ECBMR project respectively. So, the net profit that will be obtained from these project reach US$ 424,180,981. A detail calculation showed in Table 8 and Table 9. In addition, this project is expected to add more income to the company about US$ 369 million from EOR and about US$ 21.5 thousand from ECBMR, if oil and natural gas prices are US$ 69.87/bbl and US$ 3.2/MMBTU.

Conclusions This paper is developed the scenario proposed by Abdassah, et al work with utilisation of CO2 from Natuna field for EOR and ECBMR in Central Sumatra Basin. The mixed gas injection process is conducted by using integrated pipeline system and during 20 years early production, the natural gas has been produced using slug catcher finger type on the sea bed to separate it from CO2. The results show the increase of oil recovery factor and CBM recovery factor which is run using CMGTM software simulation. This paper also proves gas recovery factor, i.e. 74.17% and 128.33% and oil recovery factor, i.e. 21% and 64%, before and after the injection. This scenario is very worthy project because the operator of Natuna field will earn net profit around US$ 424,180,981 with assumption the oil and natural gas price will be constant which are US$ 69.87/bbl and US$ 3.2/MMBTU.

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Jurnal Riset Energi HMTM “PATRA” ITB Output of this study is to increase oil and CBM recovery factor, reduce global warming due to CO2 injection into reservoirs because CO2 is absorbed by coal seam in CBM reservoir. Acknowledgment The authors wish to thank Ir. Leksono Mucharam, M.Sc., Ph.D. and Dr. Ir. Amega Yasutra, MT. for guiding us to make this paper, and also Efsion Andre S.T. ,Boreyes committees for permitting to publish this paper.

Nomenclature 𝑅𝑒 = 𝑅𝑒𝑦𝑛𝑜𝑙𝑑 𝑛𝑢𝑚𝑏𝑒𝑟, 𝑑𝑖𝑚𝑒𝑛𝑠𝑖𝑜𝑛𝑙𝑒𝑠𝑠 𝑢𝑛𝑖𝑡 𝜌 = 𝑔𝑎𝑠 𝑑𝑒𝑛𝑠𝑖𝑡𝑦, 𝑙𝑏𝑚/𝑓𝑡 3 𝑣 = 𝑔𝑎𝑠 𝑣𝑒𝑙𝑜𝑐𝑖𝑡𝑦, 𝑓𝑡/𝑠 𝐷 = 𝑝𝑖𝑝𝑒 𝑑𝑖𝑎𝑚𝑒𝑡𝑒𝑟, 𝑓𝑡 𝜇 = 𝑔𝑎𝑠 𝑣𝑖𝑠𝑐𝑜𝑠𝑖𝑡𝑦, 𝑐𝑃 𝑓 = 𝑓𝑟𝑖𝑐𝑡𝑖𝑜𝑛 𝑓𝑎𝑐𝑡𝑜𝑟, 𝑑𝑖𝑚𝑒𝑛𝑠𝑖𝑜𝑛𝑙𝑒𝑠𝑠 𝑢𝑛𝑖𝑡 𝑄 = 𝑔𝑎𝑠 𝑓𝑙𝑜𝑤𝑟𝑎𝑡𝑒, 𝑐𝑓ℎ 𝑇𝑏 = 𝑏𝑎𝑠𝑒 𝑡𝑒𝑚𝑝𝑒𝑟𝑎𝑡𝑢𝑟𝑒, 𝑅 𝑃𝑏 = 𝑏𝑎𝑠𝑒 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒, 𝑝𝑠𝑖𝑎 𝑃1 = 𝑖𝑛𝑙𝑒𝑡 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒, 𝑝𝑠𝑖𝑎 𝑃2 = 𝑜𝑢𝑡𝑙𝑒𝑡 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒, 𝑝𝑠𝑖𝑎 𝛾𝑔 = 𝑔𝑎𝑠 𝑠𝑝𝑒𝑐𝑖𝑓𝑖𝑐 𝑔𝑟𝑎𝑣𝑖𝑡𝑦 𝑇 = 𝑎𝑣𝑒𝑟𝑎𝑔𝑒 𝑓𝑙𝑜𝑤𝑖𝑛𝑔 𝑡𝑒𝑚𝑝𝑒𝑟𝑎𝑡𝑢𝑟𝑒, 𝑅 𝐿 = 𝑙𝑒𝑛𝑔𝑡ℎ 𝑜𝑓 𝑝𝑖𝑝𝑒, 𝑚𝑖𝑙𝑒𝑠 𝑍 = 𝑔𝑎𝑠 𝑑𝑒𝑣𝑖𝑎𝑡𝑖𝑜𝑛 𝑓𝑎𝑐𝑡𝑜𝑟 𝑎𝑡 𝑓𝑙𝑜𝑤𝑖𝑛𝑔 𝑡𝑒𝑚𝑝𝑒𝑟𝑎𝑡𝑢𝑟𝑒 𝑎𝑛𝑑 𝑎𝑣𝑒𝑟𝑎𝑔𝑒 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒

References

Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 58

Jurnal Riset Energi HMTM “PATRA” ITB 1. Fenter, D.J. and Hadiatno, J. : “Reservoir Simulation Modelling of Natuna Gas Field for Reservoir Evaluation and Development Planning”. SPE 37026 (1996) 2. Hanif, A. And Green, M.L.H. : “Possible Utilisation of CO2 on Natuna’s Gas Field Using Dry Reforming of Methane to Syngas (CO & H2)”. SPE 77926 (2002) 3. Al-Hasami et al., : “CO2 Injection for Enhanced Gas Recovery and GeoStorage: Reservoir Simulation and Economics”. SPE 94129 (2005) 4. Mazumer et al., : “The Late Miocene Coalbed Methane System in the South Sumatra Basin of Indonesia”. SPE 133488 (2010) 5. Indonesia Energy Outlook 2016

Parameter Porosity Permeability WOC Pres Tres Depth Pb

Value 22 157, 157, 15.7 5200 2300 170 5000 1800

Unit % mD Ft Psi F Ft Psi

Table 1: Reservoir Properties for X Oil Field in Central Sumatra Komposisi Fraksi CO2 0.01 CH4 0.02 C2H6 0.02 C3H8 0.02 i-C4H10 0.03 n-C4H10 0.03 i-C5H12 0.04 n-C5H12 0.04 C6H14 0.09 C7H16 0.7 Table 2: PVT Data for X Oil Field Sumatra

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Jurnal Riset Energi HMTM “PATRA” ITB

Figure 1: X Oil Reservoir Model

Parameter Matrix porosity Fracture porosity Matrix permeability Fracture permeability Matrix pressure Fracture pressure Reservoir temperature Depth of reservoir Natural fracture spacing Fracture water saturation

Value 0.9 1.5 0.001 5 866.29 1147 105 1850 0.2 0.999

Unit % % mD mD psi psi o F ft ft (fraction)

Table 3: Data for CBM Reservoir PVT

Data Parameter CO2 CH4 Unit Langmuir volume constant 800 480.001 scf/ton Langmuir pressure constant 555.25 844.9 psi Coal desorption time 152.166 100 Day for CBM reservoir with fully-saturated methane (CH4 = 100%) Table 4: Langmuir Data for CBM Reservoir

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Jurnal Riset Energi HMTM “PATRA” ITB

Figure 2: CBM Reservoir Model Properties Length Depth of pipe Temperature Pressure Z SG Viscosity Diameter Roughness v Q Ppc Tpc Ppr Tpr

Value 782.173 500 516.87 743.6429304 0.88 0.68 0.01934 4 0.0006 15 678,857.1429 992.4 375.174 0.749 1.378

Unit Miles Meters (below sea surface) R Psia

cP Inches In Ft/s CFH Psia R

Table 5: Pipeline System Data Component N2

Molecular Weight Fraction 28 g/mol 0.005

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Jurnal Riset Energi HMTM “PATRA” ITB CO2 H2 S CH4

44 g/mol 34 g/mol 16 g/mol

0.71 0.005 0.28

Table 6: Mixed Gas Properties

Figure 3: CMGTM Simulation Result for Oil Reservoir

Figure 4: Cumulative Oil Produced for Oil Reservoir

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Jurnal Riset Energi HMTM “PATRA” ITB

Figure 5: Oil Production Rate Profile

Figure 6: CMGTM Simulation Result for CBM Reservoir

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Jurnal Riset Energi HMTM “PATRA” ITB

Figure 7: Cumulative CBM Produced for CBM Reservoir

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Jurnal Riset Energi HMTM “PATRA” ITB

Figure 8: CBM Production Rate Profile

Figure 9: Integrated Pipeline System No. Compress or

III

Locatio n Natuna field to Natuna Island Natuna Island to Mida Island Mida Island to Siantan Island Siantan Island to Jemaja Island Jemaja Island to

Distan ce (miles)

Upstrea m Pressur e (psia)

Downstre am Pressure (psia)

Compress or HP

Auxilia ry HP

Total HP requir ed

140

6000

1554.88

1600.7

160.07

1760.7 7

74.56

5000

2997.39

1145.21

114.52

1259.7 3

93.2

5000

2231.68

596.75

59.67

656.42

37.28

5000

4122.15

800.15

80.02

880.17

144.79

6000

2213.31

521.16

52.12

573.28

Divisi Riset Energi – Departemen Karya – HMTM “PATRA” ITB | 65

Jurnal Riset Energi HMTM “PATRA” ITB

VII

Bintan Island Bintan Island to Sumatr a Island Sumatr a Junctio n Pipelin e to Oil Reserv oir Sumatr a Junctio n Pipelin e to CBM Reserv oir

124.27

6000

2050.51

967.66

96.77

1064.4 3

31.07

3050.51

1622.34

137

5500

906.67

644.89

64.49

709.38

6904.1 8

TOTAL HP COMPRESSOR

Table 7: HP Compressor Required

CATEGOR Y

1 OPEX 2

3 CAPEX 4

OPEX 1

ASPECT INJECTION WELL DRILLING LNG PROJECT PIPELINE CONSTRUCTI ON SLUG CATCHER 2038 - 2088 PIPELINE CORROSION INHIBITOR

COST

300000 8500000

UNIT

US$/DA Y US$/YE AR

AMOUNT/ DURATION

UNIT

SUB-TOTAL COST

MONTH

54000000

US$

YEAR

170000000

US$

UNIT

80000000 US$

80000000

US$

2000000

US$

2000000

US$

3000000

US$/YE AR

150000000

US$

YEAR

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Jurnal Riset Energi HMTM “PATRA” ITB COMPRESSO R INSTALLATIO N TOTAL COST

CAPEX 2

800000

US$/M W

5.148

4118400 460118400

Table 8: Cost and Revenue Projection

ASPECT

METHANE PRODUCTION THROUGH 1 LNG PROJECT 2 EOR PROJECT ECBMR 3 PROJECT

REVENUE

UNIT

45920 US$/DAY

SUBTOTAL REVENU E

AMOUN T/DURAT ION

20 YEAR

18301096 US$/YEAR

30 YEAR

1010.214 US$/YEAR

50 YEAR GROSS TOTAL NET

3352160 00 5490328 70 50510.6 88 8842993 81 4241809 81

UNI T

US$ US$ US$ US$ US$

Table 9: Gross and Net Profit

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US$ US$