Jurnal Teknologi Minyak dan Gas Bumi

Web Publishing

ISSN 2088-7590

Jurnal Teknologi Minyak dan Gas Bumi JTMGB

Volume 12 Nomor 3 Desember 2016

Ikatan Ahli Teknik Perminyakan Indonesia Society of Indonesian Petroleum Engineers JTMGB

Vol. 12

No. 3

Hal. 119-208

Jakarta Desember 2016

ISSN 2088-7590

Keterangan gambar cover : Carbon Capture Storage.

Jurnal Teknologi Minyak dan Gas Bumi ISSN 0216-6410

JTMGB


Jurnal Teknologi Minyak dan Gas Bumi adalah majalah ilmiah diterbitkan setiap kwartal yang menyajikan hasil penelitian dan kajian sebagai kontribusi para professional ahli teknik perminyakan indonesia yang tergabung dalam Ikatan Ahli Teknik Perminyakan Indonesia (IATMI) dalam menyediakan media komunikasi kepada anggota IATMI pada khususnya dan mensosialisasikan dunia industri minyak dan gas bumi kepada masyarakat luas pada umumnya. KEPUTUSAN KETUA UMUM IATMI PUSAT NO: 003/SK/IATMI/III/2015 Penanggung Jawab : Ir. Alfi Rusin Pemimpin Redaksi

: Ir Raam Krisna

Redaktur Pelaksana : Ir. Andry Halim Peer Review

: Prof. Dr. Ir. Septoratno Siregar (Enhanced Oil Recovery) Prof. Dr. Ir. Pudjo Sukarno (Integrated Production System) Prof. Dr. Ir. Doddy Abdassah, PhD. (Reservoir Engineering) Dr. Ir. RS Trijana Kartoatmodjo (Production Engineering) Dr. Ir. Arsegianto (Ekonomi & Regulasi Migas) Dr. Ir. Bambang Widarsono (Penilaian Formasi) Dr. Ir. Sudjati Rachmat, DEA (Well Stimulation and Hydraulic Fracturing) Dr. Ir. Sudarmoyo, SE, MT (Penilaian Formasi) Dr. Ir. Ratnayu Sitaresmi (Penilaian Formasi - CBM) Dr. Ir. Sugiatmo Kasmungin (Reservoir Engineering) Dr. Ing. Ir. Bonar Tua Halomoan Marbun (Drilling Engineering) Suryono Adisoemarta, PhD. (Petroleum Engineering)

Senior Editor

: Ir. Junita Musu, M.Sc. Ir. Ida Prasanti Ir. Chairatil Asri

Sekretaris

: Ir. Bambang Pudjianto (IATMI)

Layout Design

: Alief Syahru Syaifulloh, S.Kom. (Sekretariat IATMI)

Sirkulasi

: Abdul Manan, A.Md. (Sekretariat IATMI) Alamat Redaksi: Patra Office Tower Lt.1 Ruang 1-C Jl. Jendral Gatot Subroto Kav. 32-34 Jakarta 12950 – Indonesia. Tel/Fax: +62-21-5203057 website: https://iatmi.or.id email: [email protected] Jurnal Teknologi Minyak dan Gas Bumi (ISSN 0216-6410) diterbitkan oleh Ikatan Ahli Teknik Perminyakan Indonesia, Jakarta Didukung oleh Fakultas Teknik Pertambangan dan Perminyakan ITB


JTMGB


DAFTAR ISI

Improved Proppant Scheduling Method in Hydraulic Fracturing Optimization Sudjati Rachmat dan Andreas Ansen Vitalis ...................................................................... 119 - 152 Comprehenship Study of Enhanced Coal Bed Methane Recovery Potential Using CO2 Injection Simulation Sudjati Rachmat dan Monica Gabriela .............................................................................. 153 - 166 Studi Laboratorium Terhadap Tegangan Antar Muka Sistem Minyak-CO2 pada Kondisi Reservoir M. Abdurrahman dan A.K. Permadi .................................................................................. 167 - 176 A Successful Innovative Pilot Project of Natural Dumpflood - Alpha Sand in Oleander Field Central Sumatra Basin Ade Fadli, Dedek Priscilla dan Muhamad Irfan ................................................................. 177 - 184 The Effect of Rock Mineral and Compositions on Surfactant Injection at Tempino Reservoir Sandstone: A Laboratory Study Taufan Marhaendrajana dan Kharisma Idea ...................................................................... 185 - 196 Techno-Economic Evaluation of Carbon Capture Storage Ready for Coal-Based Power Generation in Indonesia Usman, Sugihardjo, Danang Sismartono, Aziz M. Lubad, Oki Hedriana dan Arief Sugiyanto ........................................................................................................................... 197 - 208

KATA PENGANTAR

JTMGB Edisi Desember 2016 Para Pembaca JTMGB yang budiman, Tidak terasa dua tahun masa kepengurusan IATMI Pusat periode 2014 - 2016 berakhir dengan telah terlaksananya Simposium dan Kongres Nasional IATMI XIV (SIMGRESNAS IATMI XIV pada tanggal 6 - 8 Desember 2016. SIMGRESNAS IATMI XIV telah berhasil memilih dan menetapkan Ketua Pengurus IATMI Pusat periode 2016 - 2019. Selamat! Pada kesempatan ini atas nama segenap Pengurus IATMI periode 2016 - 2019 mengucapkan Selamat Natal dan Selamat Tahun Baru 2017, dengan doa dan harapan semoga di tahun 2017 kita semua diberikan kesehatan, kebahagiaan dan rizki yang barokah. Melalui media ini, dengan senang hati kami bisa kembali menjumpai para pembaca dengan aneka materi bacaan ilmiah yang tersaji dalam JTMGB Edisi Desember 2016, dimana kita akan membahas persoalan-persoalan (parameter) sederhana tetapi memiliki implikasi signifikan terhadap hasilnya. Di bidang produksi ada 2 (dua) tulisan, pertama menyajikan pembahasan dalam menentukan desain rekah hidrolik optimal dalam jangka hidrolik setengah-panjang dan laju injeksi fluida dengan metode Crawford yang termodifikasi; sedang kedua membahas metode peningkatan perolehan CBM dengan injeksi karbon dioksida serta aspek yang mempengaruhi faktor perolehan dan efisiensi injeksi, terutama untuk Indonesia. Di bidang reservoir/EOR ada 3 (tiga) tulisan, pertama menampilkan pembahasan konsep, proses seleksi, tantangan serta pembelajaran dari proyek percobaan natural dumpflood, sebagai percobaan awal proyek water flood berskala besar untuk meminimalisir resiko investasi pada kondisi harga minyak yang rendah; kedua menyajikan hasil penentuan tegangan antar muka (interfacial tension, IFT) minyak dan gas CO2 melalui eksperimen di laboratorium, dengan perhitungan melalui metode pendant drop; sedangkan ketiga menyajikan pembahasan untuk mengetahui pengaruh mineral dan susunan butir batuan terhadap injeksi surfaktan. Tulisan di bidang umum yang tidak kalah menariknya adalah pembahasan untuk menentukan dan mengevaluasi pembangkit batubara teknologi untuk menangkap dan menyimpan CO2 atau carbon capture storage ready pada dua kandidat pembangkit listrik batu bara. Dalam upaya meningkatkan kualitas majalah JTMGB, kami sedang mempersiapkan pengajuan akreditasi JTMGB ke LIPI, dengan mengacu kepada peraturan LIPI yang terbaru, pengajuan akreditasi akan dimulai bulan Maret 2017. Selamat menikmati bacaan edisi kali ini. !*** (Tutuka Ariadji)


Date of issue: 2016-12-29

The descriptors given are free terms. This abstract sheet may be reproduced without permission or charge. Sudjati Rachmat (Institut Teknologi Bandung) Andreas Ansen Vitalis (Institut Teknologi Bandung) Improved Proppant Scheduling Method in Hydraulic Fracturing Optimization Perbaikan Metoda Proppant Scheduling pada Optimisasi Perekahan Hidraulik JTMGB. Desember 2016, Vol. 12 No. 3, p 119-152 Hydraulic fracturing is a well-stimulation technique often used to increase productivity of low and moderate permeability reservoirs. Fracturing is generated hydrautically by injecting reservoir that the rate is too high for the formation to accept without breaking. During injection, the pressure in the wellbore increases to a value called the break-down pressure. Once the formation breaks down, a fracture is formed, and the established fracture is kept open by using proppants. Proppant Scheduling Method by definition is a method of hydraulic fracturing treatment to executes a pump schedule that includes pad fluid volume, and proppant stage concentration. This method is used to optimize the fracture conductivity. Proppant Scheduling initiated by Harrington, et. al. when he published his paper in 1973. Later, in 1983, Crawford made an inovation by creating a simple straightforward method, ‘Proppant Scheduling Method,’ to establish an efficient proppant schedule. Nowdays, a new automated Pump Scheduling Generator, PSG, has become a primary tool to achieve optimum fracture conductivity. But this method become cumbersome when no simulator available because of its nature of numerical solution. This study aimed to modify Crawford’s method. This new method within reasonable accuracy is as good as PSG method, but simpler to generate. Parameters that are used to modify the method are maximum fracture width, average propped width, total proppant mass, volume of treatment fluid required. The modified Crawford’s method is used to determine the optimum hydraulic fracture design in term of hydraulic half-length and fluid injection rate. Simulations are run using Khristianovic-Geertsmade Klerk (KGD) geometry model to model fracture propagation in order to obtain fracture conductivity and Fold of Increase (FOI). The optimum hydraulic design then selected based on optimum FOI scenario. Keywords: Hydraulic Fracturing, Proppant Scheduling Method, PSG, FOI.

Sudjati Rachmat (Institut Teknologi Bandung) Monica Gabriela (Institut Teknologi Bandung) Comprehenship Study of Enhanced Coal Bed Methane Recovery Potential Using CO2 Injection Simulation Studi Komprehensip tentang Peningkatan Potensi Perolehan Gas Metana Batubara dengan Simulasi Injeksi CO2 JTMGB. Desember 2016, Vol. 12 No. 3, p 153-166 As conventional oil and gas production keeps declining rapidly in Indonesia, coal bed methane (CBM) is an unconventional energy source worth to be explored more, as Indonesia has a huge CBM potential which is estimated to be 6% of total global CBM reserves. Unfortunately since 2008, CBM production hasn’t been satisficing as it hasn’t reached its target which is only 1 MMSCFD. Looking at its enormous potential and the reality that CBM production is steadily low a further study is carried out to accomplish a comprehensive understanding about this unconventional energy source. Particularly, a research is performed to investigate Indonesia’s CBM reservoir potential to be implemented an enhanced CBM recovery (ECBM) method: carbon dioxide injection. A simulation study is conducted to Indonesia’s CBM reservoir in Sanga Sanga, Kalimantan, named Field H. The objectives of this simulation study is to know whether Field H is a good candidate for carbon dioxide injection to increase CBM production, and to do sensitivity study regarding the injector-producer wells patterns and carbon dioxide injection rate effect to CBM gas recovery factor and injection efficiency. At the end of the study, all the discussions and simulation results gathered will draw a conclusion on carbon dioxide injection’s potential to increase Indonesia’s CBM production, as well as the factors affecting the recovery factor and injection efficiency. This paper is a comprehensive study from literatures such as articles, papers, and publications, as well as data collection and simulation of carbon dioxide injection in Field H, Kalimantan’s CBM reservoir. This comprehensive study presents a novel discussion about CBM, its gas and reservoir characterization, production process, ECBM methods, and finally carbon dioxide injection simulation and analysis of the results, particularly for Indonesia. Keywords: Coal bed methane, CBM, Indonesia, carbon dioxide injection.

M. Abdurrahman (Universitas Islam Riau) A.K. Permadi (Institut Teknologi Bandung) Studi Laboratorium Terhadap Tegangan Antar Muka Sistem Minyak-CO2 Pada Kondisi Reservoir A Laboratory Study on the Interfacial Tension of OilCO2 System at Reservoir Conditions JTMGB. Desember 2016, Vol. 12 No. 3, p 167-176 Dua sebab utama turunnya produksi minyak nasional adalah keadaan lapangan yang sudah tua dan tekanan yang terus menurun. Sementara itu, tahap produksi umumnya masih didominasi oleh tahap primer dan sekunder. Dengan demikian, diperlukan metode lanjutan, yaitu metode enhanced oil recovery (EOR), untuk meningkatkan perolehan minyak. Metode tersebut di antaranya adalah injeksi kimia, gas, atau injeksi uap. Injeksi gas merupakan metode yang sudah matang dan telah terbukti dapat meningkatkan perolehan minyak. Indonesia memiliki sejumlah lapangan gas dengan kandungan CO2 yang tinggi di sejumlah wilayah kerja. Sumber gas CO2 tersebut sangat berpotensi untuk digunakan dalam metode injeksi gas dalam rangka meningkatkan perolehan minyak. Studi yang disajikan dalam makalah ini bertujuan untuk menentukan tegangan antar muka (interfacial tension, IFT) antara minyak dan gas CO2 melalui eksperimen di laboratorium pada temperatur 40oC, 60oC, dan 80oC. Tekanan yang diberikan berada pada kisaran 700 psi sampai 1800 psi. Melalui penelitian ini, dapat diketahui besarnya penurunan tegangan antar muka pada kondisi reservoir. Tegangan antar muka ditentukan dengan cara perhitungan melalui metode pendant drop. Sampel minyak yang digunakan dalam penelitian ini diambil dari salah satu lapisan yang berada di Formasi Air Benakat, Cekungan Sumatera Selatan. Hasil studi menunjukkan bahwa tegangan antar muka CO2 dan sampel minyak turun secara signifikan seiring dengan kenaikan tekanan. Pada temperatur 40oC terjadi penurunan tegangan antar muka dari 23,16 dyne/ cm menjadi 0,83 dyne/cm. Pada temperatur 60oC terjadi penurunan tegangan antar muka dari 24,25 dyne/cm menjadi 2,52 dyne/cm. Pada temperatur 80oC terjadi penurunan tegangan antar muka dari 25,88 dyne/cm menjadi 3,33 dyne/cm. Kenaikan tekanan menyebabkan penurunan tegangan antar muka dan sebaliknya kenaikan temperatur menyebabkan kenaikan tegangan antar muka. Studi semacam ini sangat penting dilakukan sebelum melakukan injeksi CO2 di lapangan yang diinginkan. Tegangan antar muka sangat erat kaitannya dengan parameter penting lainnya seperti wettability, tekanan kapiler, dan dispersi gas. Dengan mengetahui besarnya penurunan tegangan antar muka maka dapat diketahui perubahan yang terjadi pada ketiga paremeter diatas. Perubahan parameter-parameter tersebut akan memberikan kontribusi yang sangat signifikan terhadap mekanisme penambahan produksi minyak melalui injeksi gas CO2. Kata Kunci: Tegangan antar muka, injeksi CO2, peningkatan perolehan, metode pendant drop.

Ade Fadli (Chevron Pasific Indonesia) Dedek Priscilla (Chevron Pasific Indonesia) Muhamad Irfan (Chevron Pasific Indonesia) A Successful Innovative Pilot Project of Natural Dumpflood - Alpha Sand in Oleander Field Central Sumatra Basin Keberhasilan Proyek Inovasi Natural Dumpflood di Lapangan Minyak Oleander, Reservoir Alpha, Cekungan Sumatera Tengah JTMGB. Desember 2016, Vol. 12 No. 3, p 177-184 The recent downturn in oil price has impacted capital expenditure and risk appetite. Strong economic justification is required for a project to be executed, where projects with minimum capital investment and low risk are highly preferable. Addressing this challenge in CPI operating area; a natural dumpflood has been successfully implemented in Oleander Field, an oil field under primary recovery in the Central Sumatera Basin. Unlike a traditional surface water injection, reservoir target is flooded by utilizing pressure contrast between two reservoirs to create natural cross flow, therefore eliminating the need for water treatment facilities, pipelines and surface injection pumps. Recent surveillance in newly drilled wells has confirmed that the current reservoir pressure of Alpha Sand is approximately 35% of the original reservoir pressure. This 125 acre sand-stone reservoir is designated as natural dumpflood target after evaluating remaining reserves, OOIP, rock properties, and connectivity. Situated 1000 ft above Alpha Sand, a non-productive, high pressure reservoir called Bravo Sand is selected as water-source for natural dumpflood. An idle well located at the flank was converted to injection well via a low cost workover to enable the natural flooding. Fluid compatibility testing was undertaken. Post injection surveillance was established on both injector and adjacent producers to monitor pressure response. This paper present the concept, selection process, challenges and best practices of natural dumpflood Pilot Project. Significant production gains have been observed a few months after initiating the dumpflood. With minimal investment and short initiation times, this pilot has been economically viable and has the potential to be implemented in other fields. Other potential applications include using a dumpflood to pilot a larger scale waterflood in order to de-risk a large investment in a low oil price environment. Keywords: Surveillance, Dumpflood, Cross Flow.

Waterflood,

Natural

Taufan Marheandrajana (Institut Teknologi Bandung) Kharisma Idea (UPN “Veteran” Yogyakarta) The Effect of Rock Mineral and Compositions on Surfactant Injection at Tempino Reservoir Sandstone: A Laboratory Study Pengaruh Mineralogi dan Komposisi Batuan Terhadap Injeksi Surfaktan di Lapangan Tempino Reservoir Batupasir: Studi Laboratorium JTMGB. Desember 2016, Vol. 12 No. 3, p 185-196 The purpose of this study is to investigate the effect of mineral and rock grains composition onthe anionic surfactant injection. Three surfactants were used. Two are anionic Alkyl Carboxylate added bynon-ionic cosurfactant and subtle amount of polymer (namely AN2NS and AN3NS). They differ only on the content of non-ionic co surfactant.The other was non-ionic surfactant Alkyl Ester Polyethylene Glycol (NSS-26C).Surfactant injection was performed oncores of Berea and Tempino Field. On a laboratory scale, the surfactants were tested for aqueous stability, phase behavior, Critical Micelle Concentration (CMC), and thermal stability. Mineral contents and grain composition of rocks was done by using X-ray Diffraction (XRD), Petrographic, Scanning Electron Microscope (SEM) and Energy Dispersive X-ray Spectroscopy (EDS). Observation in this study suggested that the present of calcite and dolomite (with Ca and Mg positive charges) and clay as cement that fill the pores react with anionic surfactant (negative head charged forms deposit inside pores that decrease porosity of core at the time of injection. The interlocking porosity and secondary porosity with carbonates and clay cement cause trap residual oil difficult to be displaced by surfactant injection. On the other hand, the presence granule with carbonate matrix arranged in layers assist injection when its bedding direction is parallel to the flow direction. Keywords: Surfactant Injection, Tempino Oil Field, Anionic Surfactant, Non-ionic Surfactant.

Usman (PPPTMGB “LEMIGAS”) Sugihardjo (PPPTMGB “LEMIGAS”) Danang Sismartono (PPPTMGB “LEMIGAS”) Aziz M. Lubad (PPPTMGB “LEMIGAS”) Oki Hedriana (PPPTMGB “LEMIGAS”) Arief Sugiyanto (Perusahaan Listrik Negara) Techno-Economic Evaluation of Carbon Capture Storage Ready for Coal-Based Power Generation in Indonesia Evaluasi Tekno-Ekonomi untuk Pembangkit Listrik Berbasis Batubara di Indonesia JTMGB. Desember 2016, Vol. 12 No. 3, p 197-208 To meet the rapidly growing demand and to provide secure base load power supply, Indonesia’s power sector is seeing a growing share of coal in its generation mix. However, increased coal-based generation contributes to increased CO2 emissions. This study aims to define and evaluate the conditions under which coal-based generation could be deemed as carbon capture and storage ready. It considers the technical and economic implications of CO2 capture and storage for two candidate coal power plants in South Sumatera and West Java. A carbon capture storage of a couple of scenarios are evaluated for each power plant based on separation of 90%, 45% and 22.5% of CO2 from the power plant flue gas with an amine scrubbing process, supported by flue gas cleaning processes, and liquefaction of the captured CO2 for transportation to geological storage locations. The carbon capture storage operation would also run for 20 years, 15 years and 10 years, while the power plant design life is 25 years. The potential to sell captured CO2 for enhanced oil recovery in South Sumatera is also assessed. Results of this study will help Indonesia to identify a way to reduce CO2 emissions from the coalbased power sector in the long run and will contribute significantly to putting the country’s energy sector on a sustainable development path. Keywords: CCS-ready; coal power plant; CO2 capture, CO2 emissions; CO2 EOR.

Improved Proppant Scheduling Method in Hydraulic Fracturing Optimization Perbaikan Metoda Proppant Scheduling pada Optimisasi Perekahan Hidraulik Sudjati Rachmat1 dan Andreas Ansen Vitalis2 [email protected] (1)(2)Petroleum Engineering Department, Institut Teknologi Bandung, Jl. Ganesha 10, Bandung 40132, Tel. +6222-2504955

Abstract Hydraulic fracturing is a well-stimulation technique often used to increase productivity of low and moderate permeability reservoirs. Fracturing is generated hydrautically by injecting reservoir that the rate is too high for the formation to accept without breaking. During injection, the pressure in the wellbore increases to a value called the break-down pressure. Once the formation breaks down, a fracture is formed, and the established fracture is kept open by using proppants. Proppant Scheduling Method by definition is a method of hydraulic fracturing treatment to executes a pump schedule that includes pad fluid volume, and proppant stage concentration. This method is used to optimize the fracture conductivity. Proppant Scheduling initiated by Harrington, et. al. when he published his paper in 1973. Later, in 1983, Crawford made an inovation by creating a simple straightforward method, ‘Proppant Scheduling Method,’ to establish an efficient proppant schedule. Nowdays, a new automated Pump Scheduling Generator, PSG, has become a primary tool to achieve optimum fracture conductivity. But this method become cumbersome when no simulator available because of its nature of numerical solution. This study aimed to modify Crawford’s method. This new method within reasonable accuracy is as good as PSG method, but simpler to generate. Parameters that are used to modify the method are maximum fracture width, average propped width, total proppant mass, volume of treatment fluid required. The modified Crawford’s method is used to determine the optimum hydraulic fracture design in term of hydraulic half-length and fluid injection rate. Simulations are run using Khristianovic-Geertsma-de Klerk (KGD) geometry model to model fracture propagation in order to obtain fracture conductivity and Fold of Increase (FOI). The optimum hydraulic design then selected based on optimum FOI scenario. Keywords: Hydraulic Fracturing, Proppant Scheduling Method, PSG, FOI. Abstrak Rekah hidrolik adalah teknik stimulasi sumur yang sering digunakan untuk meningkatkan produktivitas pada reservoir permeabilitas rendah dan moderat. Rekah dihasilkan secara hidrolik dengan menginjeksikan fluida ke dalam reservoar dimana laju alirnya jauh lebih tinggi dibandingkan yang dapat ditangani reservoar. Selama injeksi, tekanan dalam meningkatkan sumur bor naik hingga mencapai nilai tekanan yang disebut tekanan rekah. Setelah formasi terekahkan, rekahan tersebut dijaga tetap terbuka dengan menggunakan proppant. Metode penjadwalan proppant menurut definisi adalah metode rekah hidrolik untuk mengeksekusi jadwal pompa yang meliputi volume fluida pad, dan tahap petambahan konsentrasi proppant. Metode ini digunakan untuk mengoptimalkan konduktivitas rekah. Penjadwalan proppant diprakarsai oleh Harrington, dkk. ketika ia menerbitkan makalahnya pada tahun 1973. Kemudian, pada tahun 1983, Crawford membuat inovasi dengan menciptakan sebuah metode sederhana, ‘Proppant Scheduling Method,’ untuk membuat jadwal proppant yang efisien. Saat ini, metode baru, Pump Scheduling method, PSG, telah menjadi alat utama untuk mencapai konduktivitas rekah optimal. Namun metode ini menjadi menyusahkan ketika tidak ada simulator yang tersedia karena metode ini menggunakan solusi numerik. Penelitian ini bertujuan untuk memodifikasi metode Crawford. Metode baru ini dalam ketelitian yang baik menghasilkan sebaik metode PSG namun tetap lebih sederhana dipersiapkannya. Parameter yang dijadikan dasar untuk memodifikasi metode ini adalah lebar rekah maksimum, lebar rekah rata-rata, total massa

119

120

JTMGB, Vol. 12 No. 3 Desember 2016: 119-152

proppant, volume fluida yang diperlukan. dimodifikasi metode Crawford digunakan untuk menentukan desain rekah hidrolik optimal dalam jangka hidrolik setengah-panjang dan laju injeksi fluida. Simulasi dijalankan menggunakan model geometri Khristianovic-Geertsma-de Klerk (KG) untuk model propagasi rekah untuk mendapatkan konduktivitas rekah dan Lipat dari Kenaikan (FOI). Desain hidrolik optimum kemudian dipilih berdasarkan skenario FOI optimal. Kata kunci: Rekah Hidrolik, Metode Penjadwalan Proppant, PSG, FOI.

I. INTRODUCTION

1983) in the way within reasonable accuracy is as good asit can match the Pump Schedule Generator (Gu, H. et. al, 2003) parameters 1.1 Background based on fracture width, fracture average propped fracture width, total proppant mass, Proppant Scheduling initiated by and total treatment fluid design. Harrington, et. al. when he published his paper in 1973. Later, in 1983, Crawford made an inovation 2. Determine the optimum value of fracture half-length and optimum value of injection by creating a simple straightforward method, ‘Proppant Scheduling Method,’. Proppant rate design for hydraulic fracturing in field x. Scheduling Method by definition is a method of hydraulic fracturing treatment to executes a 3.1 Scope and Limitations pump schedule that includes pad fluid volume, and proppant stage concentration. This method The scope of this study has been limited is used to optimize the fracture conductivity. to modifying Crawford’s method based on Nowdays, a new automated Pump Scheduling maximum fracture width, average propped MethodGenerator, PSG, has become a primary width, total proppant mass, volume of treatment tool to achieve optimum fracture conductivity. fluid required. Simulations are run using KGD But this method become cumbersome when geometry model to model fracture propagation. no simulator available because of its nature of A simulation software FracCADE 5.1 used in numerical solution. This study aimed to create order to obtain fracture conductivity and Fold of a modifiedmodify Crawford’s method. This new Increase (FOI). The optimum hydraulic design method within reasonable accuracy is as good as selected based on optimum FOI scenario. The perhaps can match the accuracy of PSG method, limitation of this study is based on the input but simpler to generateyet simple to generated. parameters for the simulator. The availability of input data may vary depend on the real-condition II. PROBLEM STATEMENT data of gas wells around the world. Based on background studies, writer IV. RESERACH METHODOLOGY conclude two main problems that can be evaluated, there are: The methodology in this study are as 1. Is there any way to improve the old ‘proppant follows: scheduling method’ (Crawford, H. R, 1983) so it can match the new ‘Pump Schedule Generator’ method (Guo, H. et. al, 2003)? 2. What is the the optimum value of fracture half-length and injection rate for hydraulic fracturing design in field x. III. OBJECTIVES The primary objectives of this study are: 1. To modify the proppant Proppant scheduling Scheduling method Method (Crawford, H. R, Figure 1. Study Workflow Chart.

Improved Proppant Scheduling Method in Hydraulic Fracturing Optimization

121

(Sudjati Rachmat dan Andreas Ansen Vitalis)

V. BASIC THEORY 5.1 Young’s Modulus Modulus of elasticity is mechanical property of linear elastic solid materials. It defines the relationship between stress (force per unit area) and strain (proportional deformation) in a material.

where E = Young’s modulus (modulus of elasticity) F = Force exerted on an object under tension A0 = Actual cross-sectional area through which the force is applied ∆L = Amount by which the length of the object changes L0 = Original length of the object. 5.2 Poisson’s Ratio

where σv = overburden stress (psi) ρ = the average density of overburden formation (lb/ft3) H = depth (ft) The overburden stress is carried by both the rock grains and the fluid within the pore space between the grains. The contact stress between grains is called effective stress. Effective The effective stress can be calculated from this the following equation:

where σ’v = effective vertical stress (psi) α = Biot’s poro-elastic constant, approximately 0.7 pp = pore pressure (psi)

The Poisson’s ratio is the ratio of The effective transverse contraction strain to longitudinal expressed as extension strain in the direction of stretching force. Assuming that the material is stretched or compressed along the axial direction,

horizontal

stress

is

where v = Poison’s ratio where v = resulting Poisson’s ratio εtrans = transverse strain εaxial = axial strain 5.3 Breakdown Pressure Formation fracturing pressure is also called breakdown pressure. It indicates the pressure at which the formation rock will break and allow fluids to flow inside. Breakdown The breakdown Pressure pressure value is used to access the formation treatment operations. Breakdown The breakdown pressure estimation start with in-situ stress analysis. This stress caused by the weight of the overburden formation in the vertical direction is expressed as

The total horizontal stress is expressed as

The maximum horizontal stress is

where: σtect = tectonic stress Based on a failure criterion, Terzaghi presented the following expression for the breakdown pressure:

122


where: T0 = tensile strength of the rock

and the deposition of proppants • Fluid viscosity being too high can might result in excessive injection pressure during the treatment 5.7 Proppant Proppant used to be mixed in the slurry, to keep the fracture created by the pad fluid open after the well is shut-in. Usually there are 4 four types of proppant: • Sand • Resin-coated Sand • Ceramic • Resin-coated Ceramic

Figure 2. Pressure profile against time in a typical hydraulic fracturing treatment (Schechter, 1992).

When the closure stress increasing, the proppant will be less permeable. 5.8 Proppant Permeability

5.4 Propagation Pressure

Final The final fracture permeability is strictly a function of the diameter of the proppant The Propagation Pressure is the pressure particles used in the treatment. According to the required to continually enlarge the fracture. Blake-Cozeny equation:6 5.5 Instantaneous Shut-in Pressure The Instantaneous Shut-in Pressures is the pressure that is required to just hold the where fracture opened. dp = diameter of the proppant particle Øf = porosity of the packed, multilayer bed 5.6 Fracturing Fluid of the proppant particles. The fracturing fluid which should have functions of: 1. gives enough hydraulic pressure to fracture the target formation and propagates it until the target fracture length. 2. controls the efficiencies of carrying proppant to fill the fracture. The fluid loss and the fluid viscosity are the major fracture design variables • Excessive fluid loss prevents fracture propagation because of the insufficient fluid volume accumulation • Fracture fluid with the lowest possible value of fluid-loss (leak-off) coefficient should be selected Figure 3. Sketch depicting various proppant arrangements • Viscosity affects transporting, suspending, (Schechter, 1992).

Improved Proppant Scheduling Method in Hydraulic Fracturing Optimization (Sudjati Rachmat dan Andreas Ansen Vitalis)

123

5.9 Hydraulic Fraturing Job A hydraulic fracturing job is divided into several stages of injecting fluid from surface into target formation. Commonly the stages are pad stage and slurry stage. PreThe pre-pad stage and the flush stage may be done.

Figure 6. End Job stage (Guo, 2007).

After that, the fracturing job is over and the pump is shut down to allow any fluid to break completely back to water and lead to leak off so that the fracture will close and then press the proppant pack. Figure 4. Pad Stage (Guo, 2007).

5.10

Crawford’s Method

Proppant

Scheduling

In the pad stage, the fracturing fluid This PSM method aimed to give accurate is injected into the well to break down the method to: formation and create a pad. After the pad grows to desirable size, the slurry stage started. During 1. determine the amount of fracking fluid needed without wasteful overdesign, this stage, the fracturing fluid is mixed with 2. establish an efficient proppant schedule proppant and the mixture is injected into the pad which simultaneously provides high fracture / fracture. conductivity, long propped lengths and low odds of a tip screenout. To obtain the purposes of this method, Crawford create a straightforward and simple use of Harrington, Whitsett, and Hannah equation to calculate fracture area and fluid loss during fracturing.

Figure 5. Slurry Stage (Guo, 2007).

PreThe pre-pad stage may be needed before the pad stage to cool down the formation, especially in a high temperature formation, commonly using slick water. Flush The flush stage is needed at the end of the job, after the slurry stage, to ensure that all the proppant slurry injected during the slurry stage, and to clean the wellbore from proppant. This stage is commonly use slick water as the flush fluid.

where A V W C T VFL

= Area of one face of the fracture which is created during injection (ft2) = Total volume of liquid slurry proppant) pumped (cu ft) = Average propped width (ft) = Fluid loss coefficient (ft /min0.5) = Total time of injection (minutes) = Volume of fluid lost (cu ft)

124


5.11 Fracture Propogation Model: KGD

5.13 Fracture Conductivity

This model assuming that a fixed-height vertical fracture is propagated in a well-confined pay zone. In other word this model would valid if the stresses in the layers above and below the pay zone are large enough to prevent fracture growth out of the pay zone. In this model, the width of the crack at any distance from the well is independent of vertical position, which is a reasonable approximation for a fracture with height much greater than its length.

The productivity of fractured wells depends on two steps: receiving fluids from formation, and transporting the received fluid to the wellbore. Usually one of the steps is a limiting step that controls the well-production rate. The efficiency of the first step depends on fracture dimension (length and height), and the efficiency of the second step depends on fracture permeability. The concept of fracture conductivity defined as (Argawal et al., 1979; Cinco-Ley and Samaniego, 1981):

where FCD kf w xf

= fracture conductivity (dimensionless) = fracture permeability (md) = fracture width (ft) = fracture half-length (ft)

5.14 Equivalent Skin Factor

Figure 7. KGD Fracture Geometry Model (Guo, 2007).

The equivalent skin factor can be calculated using Valko et al. (1997) correlation:

5.12 Fracture Propogation Model: PKN where The Perkins-Kern-Nordgren, PKN, u = ln (FCD) Perkins and Kern (1961) also derived a solution for a fixed height vertical fracture. This model 5.15 Fold of Increase (FOI) will be valided valid when the fracture length is at least three times the height. The fold of increase can be expressed as

where J = productivity of fractured well (stb/day psi) J0 = productivity of nonfractured well (stb/ day-psi) For xf < 0.5 re, the fold of increase expressed as:

Figure 8. PKN Fracture Geometry Model (Guo, 2007).


For xf ≥ 0.5 re, the fold of increase expressed as (Guo and Schechter, 1999):

where

width can be calculated with w = 0.785 wo Match the value of width from this equation and the value assumed before. Otherwise, go back to the step number four. 7. Calculate the fracture surface area

and ze = distance between fracture tip and boundary of drainage area VI. FIELD CASE STUDY AND SIMULATION

125

A=2hL 8. Calculate total volume

The generation of proppant scheduling will follow the steps mentioned in Crawford, H. R.: “Proppant Scheduling and Calculation of 9. Calculate the pumping time Fluid Lost”, SPE-12064, 1983. 6.1 Sensitivity Scope in This Study 10. Calculate the fluid loss • Main sensitivity variables in this study are fluids injection rate and hydraulic fracture VFL = A 3 C T 0.5 half-length • The effects of this these variables will be 11. Calculate Calculate the pad volume observed along the study. Therefore, seven different fluids injection rate scenario selected Vpad = 0.4 VFL and also ten different hydraulic fracture half length to drainage radius selected 12. Crawford assume the best conductivity • Combination of each possible scenario will is achieved at 2 lb proppant/square feet be analyzed. of fracture area. So the proppant can be calculated with 6.2 Generate Proppant-Scheduling Using Crawford’s Method mprop = 2 A 1. Crawford method start with assuming the 13. Calculate the proppant volume value of h and w 2. Select hydraulic fracture half-length to drainage radius 3. Select fluids injection rate 4. Calculate average viscosity in the fracture as 14. Calculate the volume of treatment fluid function of injection rate required Vliquid = V - Vprop 5. Calculate the maximum frac width

*the detailed result of each step can be find in appendix B

6. Crawford assume the propped frac width is linear with fracture width so the propped frac

A C

= area of one face of the fracture width created during injection (cu ft) = leak of or luid loss coefficient (ft/ min0.5)

126


G = shear modulus (psi) h = fracture height (ft) K = permeability of reservoir (md) Kf = permeability of the proppant in the fracture (md) L = length of one wing of the propped fracture (ft) mprop = proppant total mass (lb) q = fluid injection rate (bbl/min) re = drainage radius rw = well radius T = total injection time (min) V = total volume (cu ft) Vf = modified total volume (cu ft) VFL = volume of fluid lost (cu ft) Vpad = volume of pad (cu ft) Vprop = volume of proppant (cu ft) w = average frac width (in) wo = effective width wof = modified effective width ρprop = density of proppant (ppg) 6.3 Generate Proppant-Scheduling Parameter Using PSG Method

calculated in a way as same as before. 4. Calculate the average viscosity in the fracture as function of the injection rate

5. Calculate the maximum frac width

wof = 1.0617 wo - 0.0445 6. Determine the average propped frac width using the new method w = -0.1792 wof 2 + 0.6111 wof Match the value of width from this equation and the value assumed before. Otherwise, go back to the step number four. 7. Calculate the fracture surface area A=2hL

The parameters generated using simulator 8. Calculate the total volume that will be observed: 1. Maximum frac width 2. Average propped width 3. Total proppant mass 4. Volume of treatment fluid required These parameters will later become 9. Calculate the pumping time using modified total volume standard for modifying the Crawford’s method. *the detailed result can be find in appendix C

6.4 Modified Crawford’s Method

10. Calculate the fluid loss

VFL = A 3 C T 0.5 Trial-and-error of 70 cases resulting a way to modifiy the Crawford’s method. The new 11. Calculate the pad volume method uses several modified parameters: Vpad = 0.4 VFL 12. Calculate the proppant mass with the new method mprop = 0.0085 A1.6389

The other parameters should have been 13. Calculate the proppant volume


127

7.3 Calculate FOI Calculate the Fold of Increase (FOI) for 14. Calculate the volume of treatment fluid xf < 0.5 re required Vliquid = V - Vprop *the detailed result can be find in apendix D

6.5 Run Simulation using Modified Crawford’s Method as Input for Simulator

Calculate the Fold of Increase (FOI) for xf ≥ 0.5 re

The modified Crawford’s method now can be used to calculate total proppant mass and total volume of treatment fluid so the proppant schedule could be arranged for every case. This where study use simulator software: FracCADE 5.1 to simulate hydraulic fracturing job. After that the hydraulic fracturing performance for every case z = distance between fracture tip and boundary e can be evaluated. Finally, one best scenario will of drainage area be selected. *the detailed result can be find in appendix E & F

*the detailed result can be find in appendix H

VIII. CONCLUSIONS AND RECOMMENDATION

VII. ANALYSIS

7.1 Comparison between PSG, Modified 8.1 Conclusions Crawford’s Method, and the original Crawford’s Method After doing comprehensive simulations and sensitivity analysis, the conclusions of this Table 1 and Table 2 in appendix G study are: indicates the old crawford Crawford method 1. a) Proppant Scheduling Method can be will resulting a design with more proppant and improved by modifying several parameters: more treatment fluid. This can lead into higher hydraulic fracturing cost. The result also indicates modifying crawford’s method drasctically improve the ‘simple’ Proppant Scheduling Method so it can match the ‘complex’ Pump Schedule Generator. In other word the Modified Crawford’s Method will have better efficiency than the old method. 7.2 Calculate Effective Skin

where

u = ln (FCD)

b) The improved method will be resulting a proppant scheduling design with 12.4% less proppant and 5.3% less treatment fluid in comparison from unimproved methodthe PSM.

128


2. a) It is observed that hydraulic half length design value directly proportional with the FOI, meanwhile fluid injection rate inversely proportional with the FOI. But this effect of fluid injection rate can be count if the hydraulic half length more than about 1000 ft. b) Best hydraulic fracturing scenario would be: Hydraulic fracture half length = re = 1320 ft, and Fluid injection rate = 15 barrel / minutes 8.2 Recommendation This study may be continued with other parameters sensitivity, such as treatment fluid properties, proppant size, proppant type, and other technical aspects to know the feasibility of this modified Crawford’s method. A mathematical model of this modified method could be studied further to improve the design of total proppant mass and total treatment fluid needed. IX. REFERENCES Crawford, H. R.: “Proppant Scheduling and Calculation of Fluid Lost”, SPE-12064, 1983. Guo, B., Ghalambor, A., and Lyons, W. C.: “Petroleum

Production Engineering: A Computer-Assisted Approach”, Lafayette: Elsevier Science & Technology Books, 2007. Schechter, R. S.: “Oil Well Stimulation”, New Jersey: Prentice Hall, 1992. Howard, G. C. and Fast, C. R.: “Optimum Fluid Characteristics for Fracture Extension”, Drlg. and Prod. Prac., API 1957, p. 261. Harrington, L. J., Whitsett, N. F, and Hannah, R. R.: “Prediction of the Location and Movement of Fluid Interfaces in a Fracture”, presented at the Southwestern Petroleum Short Course, Texas Tech University, Lubbock, April 26-27, 1973. Coulter, G. R., and Wells, R. D., “The Advantages of High Proppant Concentration in Fracture Stimulation”, Journal of Petroleum Technology, SPE-3298, 1972 Gu, H., and Desroches, J.: “New Pump Schedule Generator for Hydraulic Fracturing Treatment Design”, SPE-81152, 2003. McLeod, H. O., “A Simplified Approach to Design of Fracturing Treatments Using High Viscosity Cross-Linked Fluids”, SPE/DOE-11614, 1983. Nolte, K. G.: “Determination of Proppant and Fluid Schedules from Fracturing-Pressure Decline”, SPE-18357, 1986. Hidayat, R., Maulana, J., Asnanda, G., and Kukuh, K., “Peningkatan Produksi Minyak Melalui Hydraulic Fracturing di Struktur Cemara”

APPENDIX A DATA


APPENDIX B CRAWFORD’S METHOD CALCULATION RESULT 1. Make starting assumption h = 160 ft w = 0.5 inch 2. Select hydraulic fracture half-length to drainage radius 0.1 *re= 132 feet 0.2 *re= 264 feet 0.3 *re= 396 feet 0.4 *re= 528 feet 0.5 *re= 660 feet 0.6 *re= 792 feet 0.7 *re= 924 feet 0.8 *re= 1056 feet 0.9 *re= 1188 feet 1 *re= 1320 feet 3. Select fluids injection rate q= 10 BPM q= 15 BPM q= 20 BPM q= 25 BPM q= 30 BPM q= 35 BPM q= 40 BPM 4. Calculate average viscosity in the fracture as function of injection rate*

129

130


5. Calculate maximum frac width*

6. Calculate average propped frac width*

7. Calculate fracture surface area


8. Calculate total volume

9. Calculate the pumping time

10. Calculate fluid loss

131

132 11. Calculate pad volume

12. Calculate proppant mass

13. Calculate proppant volume



14. Calculate volume of treatment fluid required

*result after 10th iteration

APPENDIX C PSG METHOD SIMULATION RESULT 1. Maximum frac width

2. Average propped width

133


134 3. Total proppant mass

4. Volume of treatment fluid required

APPENDIX D MODIFIED CRAWFORD’S METHOD CALCULATION RESULT 4. Calculate average viscosity in the fracture as function of injection rate*


5. Calculate maximum frac width*

6. Calculate average propped frac width*

7. Calculate fracture surface area

135

136 8. Calculate total volume

9. Calculate the pumping time

10. Calculate fluid loss



11. Calculate pad volume

12. Calculate proppant mass

13. Calculate proppant volume

137


138

14. Calculate volume of treatment fluid required

*result after 10th iteration

APPENDIX E MODIFIED CRAWFORD’S METHOD SIMULATION RESULT 1. Fluid Volume (gallons)

2. Proppant Mass (lb)


3. Slurry Volume (gallons)

4. Max hyd Frac Half-Length (ft)

5. EOJ Net Pressure (psi)

139

140


6. Propped Frac Half-Length (ft)

7. Efficiency

8. EOJ Hyd Frac Half-Length (ft)


9. Effective Conductivity (md.ft)

10. EOJ Hyd Width at Well (inch)

11. Effective Fcd

141

142


12. Propped Width at Well (inch)

13. Max Surface Pressure (psi)

14. Average Propped Width (inch)


143

APPENDIX F SURFACE GRAPH OF MODIFIED CRAWFORD’S METHOD SIMULATION RESULT 1. Fluid Volume (gallons)

2. Proppant Mass (lb)

144 3. Slurry Volume (gallons)

4. Max hyd Frac Half-Length (ft)



5. EOJ Net Pressure (psi)

6. Propped Frac Half-Length (ft)

145

146


7. Efficiency

8. EOJ Hyd Frac Half-Length (ft)


9. Effective Conductivity (md.ft)

10. EOJ Hyd Width at Well (inch)

147

148 11. Effective Fcd

12. Propped Width at Well (inch)



13. Max Surface Pressure (psi)

14. Average Propped Width (inch)

149

150


APPENDIX G COMPARISON BETWEEN PSG, MODIFIED CRAWFORD’S METHOD, AND ORIGINAL CRAWFORD’S METHOD

APPENDIX H FOLD-OF-INCREASE (FOI) CALCULATION FOR EVERY CASE 1. Calculate value of Effective Skin


2. Calculate value of ze

3. Calculate value of c

4. Calculate FOI for Xf / Re < 0.5

5. Calculate FOI for Xf / Re ≥ 0.5

151

152 6. Compile result in one table

7. FOI sensitivity result


Comprehenship Study of Enhanced Coal Bed Methane Recovery Potential Using CO2 Injection Simulation Studi Komprehensip tentang Peningkatan Potensi Perolehan Gas Metana Batubara dengan Simulasi Injeksi CO2 Sudjati Rachmat1 dan Monica Gabriela2 [email protected] (1)(2)Petroleum Engineering Department, Institut Teknologi Bandung, Jl. Ganesha 10, Bandung 40132, Tel. +6222-2504955 Abstract As conventional oil and gas production keeps declining rapidly in Indonesia, coal bed methane (CBM) is an unconventional energy source worth to be explored more, as Indonesia has a huge CBM potential which is estimated to be 6% of total global CBM reserves. Unfortunately since 2008, CBM production hasn’t been satisficing as it hasn’t reached its target which is only 1 MMSCFD. Looking at its enormous potential and the reality that CBM production is steadily low a further study is carried out to accomplish a comprehensive understanding about this unconventional energy source. Particularly, a research is performed to investigate Indonesia’s CBM reservoir potential to be implemented an enhanced CBM recovery (ECBM) method: carbon dioxide injection. A simulation study is conducted to Indonesia’s CBM reservoir in Sanga Sanga, Kalimantan, named Field H. The objectives of this simulation study is to know whether Field H is a good candidate for carbon dioxide injection to increase CBM production, and to do sensitivity study regarding the injectorproducer wells patterns and carbon dioxide injection rate effect to CBM gas recovery factor and injection efficiency. At the end of the study, all the discussions and simulation results gathered will draw a conclusion on carbon dioxide injection’s potential to increase Indonesia’s CBM production, as well as the factors affecting the recovery factor and injection efficiency. This paper is a comprehensive study from literatures such as articles, papers, and publications, as well as data collection and simulation of carbon dioxide injection in Field H, Kalimantan’s CBM reservoir. This comprehensive study presents a novel discussion about CBM, its gas and reservoir characterization, production process, ECBM methods, and finally carbon dioxide injection simulation and analysis of the results, particularly for Indonesia. Keywords: Coal bed methane, CBM, Indonesia, carbon dioxide injection. Abstrak Dengan menurunnya produksi minyak dan gas konvensional secara cepat di Indonesia, gas metana batubara (coal bed methane; CBM) menjadi sebuah sumber energi nonkonvensional yang patut dipelajari secara mendalam karena Indonesia memiliki cadangan CBM yang besar, bahkan diestimasi sebesar 6% cadangan dunia. Sayangnya sejak tahun 2008, produksi CBM belum memuaskan sebab belum dapat mencapai targetnya yang hanya 1 MMSCFD. Melihat potensi yang sedemikian besar dan kenyataan bahwa produksi CBM selalu rendah, sebuah studi dirasa perlu dilakukan untuk menghasilkan pemahaman secara komprehensif mengenai sumber energi nonkonvensional ini. Sebuah penelitian juga dilakukan untuk mengetahui potensi reservoir CBM Indonesia untuk diimplementasikan sebuah metode peningkatan perolehan CBM: injeksi karbon dioksida. Studi simulasi dilakukan di CBM reservoir Indonesia di Sanga Sanga, Kalimantan, yaitu Lapangan H. Tujuan dari simulasi ini adalah mengetahui apakah Lapangan H merupakan kandidat yang baik untuk injeksi karbon dioksida, serta untuk melakukan analisis sensitivitas pola sumur injeksi-produksi dan laju injeksi terhadap faktor perolehan dan efisiensi injeksi. Pada akhir studi, akan dihasilkan kesimpulan mengenai potensi injeksi karbon dioksida untuk meningkatkan laju produksi CBM di Indonesia, serta aspek yang mempengaruhi faktor perolehan dan efisiensi injeksi. Jurnal ini merupakan studi komprehensif dari sumber literature yaitu artikel, jurnal, dan publikasi yang telah diterbitkan, serta studi simulasi injeksi karbon dioksida di Lapangan H, reservoir CBM Kalimantan. Studi komprehensif ini berisikan pembahasan menyeluruh mengenai CBM, karakteristik gas dan reservoir CBM, proses produksi, metode peningkatan perolehan CBM,

153

154


dan akhirnya simulasi injeksi karbon dioksida beserta analisis hasilnya, terutama untuk Indonesia. Kata kunci: Gas metana batubara, CBM, Indonesia, injeksi karbon dioksida.

I. INTRODUCTION Oil and gas is one of the most important industries in Indonesia, either as an income source for the country or for Indonesia’s energy source. Getting a spotlight, oil and gas industry has grown very rapidly, especially for oil sector. During the growth, oil fields in Indonesia were exploited heavily when a conflict in Middle East occurred, as it increased oil price and therefore rousing oil production. In year 19701990, Indonesia’s economic income was highly dependent to oil sector, resulting in an enormous production which reached maximum capacity – above optimum production limit. This production level, almost always being in maximum capacity, caused a premature production decrease with a rate higher than usual. Thus, oil production has declined continuously and rapidly since 1990 until now. Indonesia, who used to be in top twenty of the highest oil producing countries and used to get a lot of surplus from oil and gas industry, has become deficit time by time1. Oil Deficit in Indonesia

condition of natural gas show a better condition than oil3. In 2016, Indonesia is still in the top twenty of the highest natural gas producing countries and top twenty of the countries having the biggest conventional natural gas reserves in the world. In 2012, Indonesia was ranked 11 of the highest natural gas producing countries (OPEC, 2012). Indonesia’s huge conventional natural gas reserve is ranked 13 in the world4. Natural gas utilization in Indonesia is growing continuously, especially for other industries (chemical, fertilizer, etc.) and PLN (Pembangkit Listrik Negara –country’s electricity generator). Indonesia was once the biggest natural gas exporter in the world, but then cutting its export volume to prioritize the consumption in the country itself first. Natural as sector is projected to have a utilization potential which will keep on increasing as it is predicted that the average growth of natural gas need in 2015-2020 is 6% per year, in 2020-2025 is 7% per year, and in 2025-2030 is 5% per year5. Because of the reasons stated above, there’s a need to further develop Indonesia’s natural gas industry. Fortunately, Indonesia not only has conventional gas reserves, but also an enormous unconventional gas reserve, coal bed methane or CBM. Knowing that natural gas reserves are already produced in a large extent and are decreasing, CBM becomes a new hope for Indonesia’s gas industry. CBM which is known as a clean-burning fuel if optimally produced can improve Indonesia’s financial and energy condition. This study’s methodology is presented in Figure 1.

Indonesia is no longer an oil exporter country, but now is an oil importer country. Indonesia is now facing a deficit from oil industry which used to be a key revenue stream for the country’s financial. Oil fields in Indonesia majorly are already old and don’t have proper enhanced oil recovery (EOR) and/or pressure maintenance strategy. This condition is worsened by the downturn of oil price in 2014-2015; Indonesia’s oil production is already limited and the price is low, making a free-fall for Indonesia’s income II. COAL BED METHANE (CBM) from oil industry. In this situation, Indonesia is pushed to find another energy resource which CBM is mostly methane and methane 2 still has a huge potential: natural gas production . combustion doesn’t emit too much emission compared to the other fossil fuels, therefore Natural Gas Sector in Indonesia CBM is called environmentally friendly fuel. CBM production gets interest from some energy Statistically, Indonesia’s natural gas industries because CBM presents energy source sector has a better data set in general compared in a large volume and considered as clean –this to oil sector. Until now, Indonesia’s natural is obviously a plus score as there is a growing gas production rate is relatively still increasing consensus in the international community that year by year. Also, the production and reserve CO2 emission from burning fossil fuels play an

Comprehenship Study of Enhanced Coal Bed Methane Recovery Potential Using CO2 Injection Simulation (Sudjati Rachmat dan Monica Gabriela)

155

of methane released into the atmosphere as a result of coal mining which contributes a lot to global warming; and (3) Giving an alternative of coal utilization when the location of coal reservoir is too deep to be mined. CBM gets more attention as conventional gas reserves lessen while natural gas price is quite increased. Coal Petrology

Figure 1. Methodology of this study.

important role in global climate change6. CBM is developed greatly in United States of America (USA), Australia (especially Queensland), United Kingdom, and China. In the USA, CBM has become a significant source of natural gas supply. From a humble beginning in 1980s, CBM production has steadily grown to the current 4.5 Bcfd, nearly 10% of total USA natural gas production7. Besides supplying natural gas, CBM development also gives some additional advantages such as: (1) Providing a cleanemission energy fuel; (2) Decreasing the amount

As geological processes apply pressure to peat over time, it transformed successively into different types of coal. Elemental analysis of coal gives empirical formula such as: C137H97O9NS for bituminous coal and C240H90O4NS for highgrade anthracite. Coal is divided into 4 ranks which is anthracite, bituminous, sub-bituminous, and lignite8. Coal components or physical parameters are made up of volatile matter, ash, and moisture content. Volatile matter consists of aliphatic carbon atoms (linked in open chains) or aromatic hydrocarbons (one or more six-carbon rings characteristics of benzene series) and mineral matter. Ash consists of inorganic matter from the earth’s crust (limestone, iron, aluminum, clay, silica, and trace elements). Each type of coal has a certain set of physical parameters which are mostly controlled by these three factors8: 1. Moisture This is simply the water content in coal, the less the water content, the better the coal rank. 2. Volatile content This aliphatic or aromatic hydrocarbon consists of mixture of gases, low-boiling point organic compounds, and tars. Volatile matter decreases as rank increases. 3. Carbon content This is dependent on coal rank, with higher rank contains less hydrogen, oxygen, and nitrogen until 95% purity of carbon is achieved at anthracite rank and above. Graphite formed from coal is the end-product of the thermal and diagenetic conversion of plant matter into pure carbon. Although coal is primarily mixture of carbon and hydrogen, sulfur is also trapped in coal, primarily in two forms which is a separate particle with no connection to the carbon atoms, or chemically bound to carbon atoms (organic

156


Table 1. Typical Coal Content for each Rank (Cassel, et. al., 2012)

sulfur). The typical content of coal based on the rank which is the degree of metamorphism or coalification as coal matures from peat to anthracite, is presented in Table 1. Geologists also classify coal types according to the organic debris called macerals, from which the coal is formed. Macerals (microscopic organic constituents found in coal) are identified microscopically by reflected light –the reflective properties indicating the individual component macerals and the way they have combined to form the coal. The purpose of classifying coal in this way is to determine its best uses. Mineral content is assessed by burning coal and measuring the ash content. Vitrinite is a type of maceral, vitrinite reflectance can be used as an indicator of maturity in hydrocarbon source rocks. To determine coal’s physical and chemical properties, there are two common tests/analyses that need to be done. The physical properties are tested by proximate test and the chemical ones are tested by ultimate test9. Because so much depends on coal’s heating ability, ultimate and proximate analysis provides invaluable information about chemical composition.

Ultimate Analysis

Ultimate analysis provides the elemental composition of oxygen, carbon, hydrogen, sulfur, and nitrogen. The tests produce more comprehensive results than the proximate analyses. Ultimate analysis is dependent on quantitative analysis of various elements present in coal sample. The results from ultimate analysis tests are used to determine the elemental composition of the coal including ash, carbon, hydrogen, nitrogen, sulfur, and oxygen (by difference). Each element is determined through chemical analysis and expressed as a percentage of the total mass of the original coal sample. The annual book of ASTM standards presents the standard method for ultimate analysis as procedure D-3176. It specifies that carbon and hydrogen of the coal will be determined from the gaseous products of the material’s complete combustion (D-3178). The total sulfur (D-3177), nitrogen (D-3179), and ash (D-3174) are to be determined from the entire material in separate calculations. The elemental analysis of coal obtained by this procedure, when converted from a weight basis to a mole basis, provides the ratios of O/C and H/C used in the van Krevelen diagram Proximate Analysis to define the maturation state of coal. This test is more of a chemical properties Proximate analysis is more of a test. It is useful in determining the quantity of physical properties testing. Proximate analysis air required for combustion and the volume indicates the percentage by weight of sulfur, and composition of the combustion gases. This moisture, volatile matter, ash, and fixed carbon information is required for the calculation of (by difference). Proximate analysis measures flame temperature and the flue duct design, etc. characteristics of coal that help predict how There are several relationships between ultimate coals will behave when handled and burned. The analysis and proximate analysis. amounts of fixed carbon and volatile combustible matter directly contribute to the heating value of Well Logging to Obtain CBM Reservoir Data coal. Fixed carbon acts as a main heat generator during burning and high volatile matter content Coal formation can be identified based indicates easy ignition of fuel. on well logging data. Low value of gamma-


ray log, low value of RHOB, and high value of resistivity indicate a coal layer. Information regarding gas content, ash content, and moisture value of CBM reservoir can be obtained from well logging data. Gas content can be calculated using logging data using some correlations. The most commonly used correlations are Mullen correlation (based on average data in San Juan Basin, New Mexico), Mavor-CloseMcBaner correlation (based on average data in Utah), Kim correlation, and modified Kim correlation10. The fact that gas content is highly related to bulk density ensures that density log is an important parameter in determining gas content. Ash content can be determined using gamma ray log and density log. In gamma ray method, radioactivity level of sample is related to ash content. In density log method, it is known that density is inversely related to ash content thus the higher the density of sample, the lower the ash content. Moisture content can be determined using neutron log and density log, based on the crossing of them. Another method is using resistivity log where the higher the resistivity of coal, the lower the moisture/water content11.

157

Gas composition Natural gas extracted from coal generally has a very high methane content compared to the one from conventional reservoir. This is because ethane and other heavier molecules are adsorbed stronger by coal surface; therefore they are not desorbed easily13. Adsorption In conventional reservoir, natural gas occupies a void space (compression process) while in coal reservoir methane is kept in coal’s surface by adsorption mechanism in coal’s micropores. A small amount of methane exists in coal’s fractures and a smaller amount is dissolved in water14. The adsorbed gas will be released as the pressure in coal’s matrix declines after water production. Water Production

The formation water needs to be produced first to decrease coal reservoir pressure so that methane gas can be released. In early times of production, the amount of water will be very high, and then it will decrease gradually after 1-2 months (generally). After that water production III. GAS IN PLACE DETERMINATION will be low and steady state. On the other hand, gas rate will increase and after it reaches the There are three mechanism of gas peak rate, will gradually decline. Gas water storage in CBM reservoir: in fractures (cleats, ratio (GWR) of CBM production will increase micropores), matrix (micropores), and soluble along time while the GWR of conventional gas gas in water (cleats). production decreases. The example of CBM 1. Fractures (cleats, micropores) production graph is in Figure 2. ............................... (1)

2. Matrix (micropores)

Gm = 1.359 ∙ A ∙ h ∙ Cgi ∙ ρg (1 - fa - fm) ......... (2)

3. Soluble gas in water (cleats) (3) Gd = Vwater ∙ Rsw ............................................... IV. CBM AND CONVENTIONAL GAS DIFFERENCES There are several differences between CBM and conventional gas in reservoir and production characteristics.

Figure 2. CBM Production Curve (Kuuskraa, 1989).

158


Gas transportation mechanism Gas diffusion in matrix micropores where mass transfer is based on methane’s gradient of concentration along micropores as driving force, agrees with Fick’s Law. After the gas reaches fractures or cleats, gas will move based on Darcy’s Law as in conventional gas reservoir where mass transfer is affected by pressure gradient. Physical properties of reservoir The optimum coal property for methane is the brittle one, having Young’s Modulus value of Figure 3. CBM Production Scheme (Ayers and Kelso, 1989) ~105 (relatively low) and pore compressibility of ~10-4 (high), also high Poisson’s Ratio. Generally the permeability value is very low (even lower than 0.1 milidarcy), thus coal reservoir needs fracturing to enable gas flow17 –the most common method is hydraulic fracturing. V. CBM PRODUCTION CBM Production scheme is presented in Figure 3. In producing CBM, there’s a stage which doesn’t exist in producing conventional natural gas: dewatering. Before CBM can be produced, reservoir pressure must be depleted by draining the water in formation. This process is called dewatering. CBM desorption is based on Langmuir Isotherm Law which describes gas adsorption in solid surface (1918). Figure 4 is the example of Langmuir Isotherm plot in Cameo Field. Gas will be desorbed if reservoir pressure reaches Langmuir Isotherm line. Initial CBM reservoir pressure almost always fall in the right side of Langmuir Isotherm line, thus gas won’t be instantly desorbed. This is the reason why dewatering process is necessary before CBM can be produced; it helps depleting reservoir pressure to reach Langmuir Isotherm line so that gas can be desorbed from the coal. Gas will be produced continuously as long as reservoir pressure is in the line.

Figure 4. Langmuir Isotherm Plot Cameo Field (Ayers and Kelso, 1989)

are two common method s for ECBM which are nitrogen injection and carbon dioxide injection. Nitrogen injection method (or can be substituted by helium) floods coal reservoir with nitrogen which is more difficult to be adsorbed by coal than methane, therefore this process maintains total pressure. When nitrogen’s partial pressure increases, methane’s partial pressure decreases, thus methane will be desorbed to stabilize the pressure. This process is called methane stripping. Nitrogen can also hold fracture width –along production, pressure will decline and narrow the fracture width, decreasing the permeability and gas production rate. Nitrogen helps overcoming this problem. Carbon dioxide method floods coal VI. ENHANCED CBM RECOVERY (ECBM) reservoir with carbon dioxide which replaces Enhanced CBM recovery (ECBM) methane in coal reservoir. Carbon dioxide is easier has some objectives: (1) Increasing ultimate to be adsorbed than methane; therefore methane recovery factor; (2) Fastening production; and will be pushed to production. This process also (3) Improving profitability and process. There helps maintaining total pressure in reservoir18.

Comprehenship Study of Enhanced Coal Bed Methane Recovery Potential Using CO2 Injection Simulation

159

(Sudjati Rachmat dan Monica Gabriela)

Carbon Dioxide Adsorption Carbon dioxide adsorption causes swelling in coal matrix and the swelling effect is greater than the one caused by methane. However, in carbon dioxide injection, although the swelling effect occurs, methane desorption in a large volume reduces coal matrix volume, enough to keep coal’s permeability value –sometimes even increase it as cleats widen and gas resistance to flow decreases19. Since CO2 affinity to solid surface is greater than CH4, carbon dioxide desorption rate will increase along the production of free water and the depletion of reservoir pressure20.

dioxide is processed to remove water content, SOx, and other impurities, and then compressed. This carbon dioxide utilization is a great potential to reduce carbon dioxide (one of the most notorious greenhouse gases) released into the atmosphere. Moreover, in some cases the process to purify carbon dioxide to meet injection criteria costs less than to meet requirements to be released into the atmosphere24. Globally, Indonesia has a high potential to isolate carbon dioxide for ECBM. Table 2. Carbon Dioxide Isolation Potential for ECBM throughout the World (Advanced Resources International, 1998).

Carbon Dioxide Injection for ECBM For this method, carbon dioxide is injected from one or more injector wells to increase methane production in producer well21. The pattern for injector-producer wells varies greatly: direct line, four-spot, five-spot, nine-spot, etc. Carbon dioxide injection in coal reservoir causes matrix swelling which reduces cleats width and matrix permeability, especially near wellbore. Swelling is the major limitation factor of this method22. Some field studies document the swelling effect and some of them can keep the permeability value23. Besides swelling effect, there are several other effects to coal physical condition such as making it There are several successful plastic, disturbing diffusion rate, and the solubility implementation of carbon dioxide injection as of methane. Carbon dioxide injection scheme is ECBM, such as in Northern Appalachian Basin, presented in Figure 5. Central Appalachian Basin, Illinois Basin, and San Juan Basin (Allison Unit). In those fields, carbon dioxide injection is proven to increase gas production rate25. VII.

Figure 5. Carbon Dioxide/Nitrogen Injection Scheme (Barzandji, et. al., 2000)

Carbon dioxide can be collected from natural source or from human activities. In most cases, this method uses carbon dioxide from human activities to also act as a greenhouse gas emission control. Before being injected, carbon

SIMULATION INJECTION

STUDY

OF

CO2

Indonesia has extensive coal deposits distributed in eleven onshore coal basins. It is estimated that Indonesia’s CBM reserves is 453 TCF –this is about 6% of total CBM reserves, making Indonesia one of some countries having the largest CBM reserves volume. The greatest reserves in Indonesia are in South Sumatera, South Kalimantan, and East Kalimantan. However, CBM reserves in Indonesia haven’t been developed in a great extent just yet. Despite the fact that CBM fields and wells have

160


been established since 2008 in Sanga Sanga, Kalimantan, the nineteen wells haven’t been producing satisfactorily. Comparing to the target rate which is 1 MMSCFD, Indonesia’s CBM production rate is quite low, about 0.1-0.5 MMSCFD. It is believed that if CBM production in Indonesia can be stimulated to reach a higher rate, Indonesia can increase natural gas export and improve its financial condition. To fulfill that goal, an ECBM method is needed to escalate CBM production rate. The potential method is CO2 injection since Indonesia has a huge potential for CO2 isolation –about 24 Giga ton per year. Indonesia is ranked six of countries emitting the largest volume of CO2 and for the last 160 years Indonesia has emitted 2.05 billion ton greenhouse gas into the atmosphere. Instead of releasing carbon dioxide gas into the air, it’s much better to utilize it for CO2 injection. To understand the effect of carbon dioxide injection into Indonesia’s CBM reservoir, a simulation study is done using a set of data depicting Indonesia’s CBM reservoir characteristics. The simulation is run using CMG-GEM for CBM reservoir. A data set for Indonesia’s CBM reservoir, Field H, Kalimantan and for the CBM gas26 are presented in Table 3. Table 3. CBM Reservoir and Gas Parameters, Field H, Kalimantan (Weatherall, et. al, 2014)

• Dual porosity model is used • Reservoir characteristics are homogenous throughout the reservoir • Reservoir characteristics are isotropic throughout the reservoir • Fluid characteristics are homogenous throughout the reservoir • Unlimited supply of carbon dioxide • Carbon dioxide used is compatible with the reservoir and the fluid • Reservoir is perforated completely

Figure 6. CBM Reservoir Field H for Simulation.

The objectives of this simulation study are: (1) Get to understand the effect of carbon dioxide injection as ECBM to CBM gas production rate; (2) Do sensitivity analysis for different injectorproducer wells patterns; and (3) Do sensitivity analysis for different carbon dioxide rate. Besides the base case, the case where there is no injector well yet –just one producer in the middle of the reservoir area, there are five injector-producer wells pattern: direct line, straight line, four spot, five spot, and nine spot. The scheme for each pattern is given in Figure 7. For each pattern or each case, six injection rates of carbon dioxide are simulated to further investigate the relation with CBM gas produced. The six injection rates are 3500 SCFD, 7000 SCFD, 14000 SCFD, 21000 SCFD, 28000 SCFD, and 35000 SCFD. Injector and producer wells parameters are presented in Table 4. The simulation is run for ten years and the injector wells are opened in the fifth year. VIII. RESULTS

To complete the data necessary to run the Production plot result for the base case simulation, there are some assumptions as below. of CBM Field H when there is only a producer


Table 4. Injector and Producer Wells Parameters.

well in the middle of the reservoir is presented in Figure 8. It can be seen that the production profile of CBM gas and water agrees with the theoretical profile. The recovery factor (RF) of the base case is 47.65%. The results after injection are presented in Table 5, showing the recovery factor (RF) of CBM gas after the reservoir is being injected by carbon dioxide, and showing also the efficiency of injection. Efficiency of injection is cumulative incremental CBM gas comparing to the base case before injection divided by cumulative carbon dioxide injected in ten years.

Generally the results show that RF increases as the carbon dioxide injection rate rises. There is only one condition where the RF after injection decreases which is when the pattern of injector-producer is two-spot and the injection rate is 3500 SCFD. The RF of this case is

161

46.79%, showing a slight decrease from the base case which means injection operation worsen the production profile. The efficiency of this case is negative, -6.58%, implying a reduction in CBM gas production compared to base case. This situation can be explained by carbon dioxide’s swelling effect on coal. As stated before, carbon dioxide injected into coal reservoir causes swelling of coal, reducing the permeability thus decreasing the production rate. This effect can be counteracted by methane production; when the carbon dioxide injection rate is adequate to push methane from coal, spaces left by methane increases the permeability, balancing or even surpassing the reduction by swelling effect. Therefore it can be concluded that in this particular case where the RF decreases and the efficiency falls below zero, the injection rate, 3500 SCFD, is not high enough for two spot pattern. The coal reservoir encountered a swelling effect but the rate is not sufficient to push the methane to production well, it only causes permeability reduction and methane entrapment. For that reason, it is important to ensure a minimum carbon dioxide injection rate for the swelling effect to be counteracted. For other cases, RF is generally rising as the injector wells are added and the injection rate is increased. To compare RF and efficiency

Table 5. RF and Efficiency Results from Simulation.

162


for each injector-producer pattern, Figure 9 and Figure 10 are plotted. In Figure 9, despite the continuous rise of RF along the increase of injection rate, at one point the elevation gradient will gradually reduce. This is obvious in nine spot pattern plot; RF keeps increasing rapidly and after injection rate of 21000 SCFD, the rise is not as high as before. Another aspect to be noted is the efficiency as shown in Figure 10. It is clear that the efficiency reaches one peak point before gradually decreases. Four spot pattern and five spot pattern reach the peak point when the injection rate is about 28000 SCFD, while nine spot pattern reaches the peak point when the injection rate is as low as 7000 SCFD. Two spot pattern and three spot pattern haven’t reached the peak point yet until the injection rate of 35000 SCFD. A decreasing value of efficiency also suggests a carbon dioxide breakthrough into producer well which means carbon dioxide is also being produced. This situation can be explained with Figure 11 and Figure 12. Five spot pattern with injection rate of 7000 SCFD simulation result is shown in Figure 11. It can be seen that gas production rate and water production rate after carbon dioxide injection starts (day 1827) escalates pretty great and there is no carbon dioxide produced yet. This means carbon dioxide breakthrough hasn’t occurred in this case. With the same injection rate of 7000 SCFD, nine spot pattern gives a carbon dioxide breakthrough condition shown in Figure 12. Gas production rate jumps significantly after the injection starts, but at a point it goes down; at the same time carbon dioxide starts to be produced. Hence according to the results of simulation study, it can be concluded that it is really necessary to find out a minimum sufficient rate of carbon dioxide injection to prevent RF reduction by swelling effect. It is also important to determine the optimum or most efficient case for carbon dioxide injection –the pattern and injection rate, by taking account of RF escalation gradient and injection efficiency. Although some cases result in a very high RF, it may not be the optimum case as sometimes the efficiency keeps decreasing and carbon dioxide breakthrough happens. It should be noticed that carbon dioxide production may affect production facilities such as production flow line; also there is an incremental cost for

Figure 7. Injector-Producer Wells Patterns for Simulation.

the produced gas to separate CBM from carbon dioxide. To determine the most optimum case, simulation itself can’t instantly give an exact answer. There are some important factors to be considered such as the supply of carbon dioxide, production and injection cost, and gas price. Looking at the results of the simulation study, it can be concluded that Indonesia’s CBM reservoir, Field H, Kalimantan, is potential for being injected with carbon dioxide. This ECBM method is compatible with Field H and resulting in a high incremental produced gas. This means there is a chance for Indonesia to increase its CBM production by implementing carbon dioxide injection into CBM reservoirs. Some essential steps to be prepared are to learn more about government regulations and build carbon dioxide purification plant; before being injected, carbon dioxide which is gathered from human activities or industrial emissions is treated to be purified from water content, etc. to ensure the quality. This is a great opportunity to utilize carbon dioxide instead of letting it into the atmosphere and worsening global warming.

Figure 8. CBM Field H Production Profile of Base Case.


163

IX. CONCLUSIONS

Figure 9. RF and Injection Rate Plot per Pattern.

Figure 10. Efficiency and Injection Rate per Pattern.

To sum up this study, there are several conclusions. 1. Indonesia’s CBM production is still far from satisfaction despite the big potential, thus a study is carried out to investigate whether carbon dioxide injection can affect Indonesia’s CBM production rate in a good manner. A simulation study is performed in Indonesia’s CBM reservoir, Field H. 2. From the simulation results, it can be concluded that a minimum sufficient rate of carbon dioxide injection must be determined to avoid RF decrease caused by swelling effect. The results also show that for each injector-producer wells patterns, even though the RF keeps increasing, there is a particular point of the most optimum injection rate, implied by the RF (the escalation gradient) and efficiency of injection value. To determine the most optimum case, a further consideration is needed. 3. Simulation study shows that Field H is a good candidate for carbon dioxide injection as it increases CBM gas production significantly. This is a great opportunity to utilize carbon dioxide as Indonesia produces a very large volume of carbon dioxide emission. X. RECOMMENDATION

For a better result and understanding, as well as a prospective further study, there are several recommendations regarding this study. Figure 11. Five Spot Pattern Production with Injection Rate 1. A more complete data (geophysics, geology, of 7000 SCFD, No Carbon Dioxide Breakthrough. reservoir, petrophysics, fluid analysis, sample laboratory test) is necessary to improve the results of simulation’s quality to depict the real condition in CBM reservoir. 2. Economic evaluation is essential to determine the best case for real implementation. 3. A study about carbon dioxide purification plant should be carried out. 4. A further investigation for ECBM can be performed to improve carbon dioxide injection, such as carbon dioxide sequestration, CO2/N2 injection, and carbon Figure 12. Nine Spot Pattern Production with Injection Rate of 7000 SCFD, Carbon Dioxide Breakthrough. dioxide huff and puff.


164 XI. NOMENCLATURES Gf = A = h = ØF = Swif = Bgi = Gm = Cgi = ρg = fa = fm = Gd = Vwater = Rsw =

initial gas in place in fractures (SCF) drainage area (acre) reservoir thickness (ft) porosity of fractures initial water saturation in fractures gas volume factor (RCF/MSCF) initial gas in place in matrix (SCF) initial gas content (SCF/ton) coal density (gr/cc) ash content moisture content soluble gas in water (SCF) water volume (STB) methane solubility in water (SCF/STB)

XII. REFERENCES Nasir, Mohamad, 2014, “Potret Kinerja Migas Indonesia”, in Buletin Info Risiko Fiskal 1st Edition, 2014. Cockroft, P., Anli, J., dan Duignan, J., 1988, EOR Potential of Indonesian Reservoirs. 17th Annual Convention of Indonesian Petroleum Association. Widarsono, Bambang, 2013, Cadangan dan Produksi Gas Bumi Nasional: Sebuah Analisis atas Potensi dan Tantangannya, Pusat Penelitian dan Pengembangan Teknologi Minyak dan Gas Bumi “LEMIGAS”, Jakarta. Badan Pengkajian dan Penerapan Teknologi (BPPT), 2014, Outlook Energi Indonesia 2014, Jakarta: Pusat Teknologi Pengembangan Sumberdaya Energi (PTPSE). Kementerian Energi dan Sumber Daya Mineral, 2014, Peta Jalan Kebijakan Gas Bumi Nasional 20142030. Wo, S. and Liang, J.T., Simulation Assessment of N2/ CO2 Contact Volume in Coal and Its Impact on Outcrop Seepage in N2/CO2 Injection for Enhanced Coalbed Methane Recovery, in SPE 14th Symposium on Improved Oil Recovery, Tulsa, Oklahoma, USA, April 17-21, 2004, SPE 89344. Stevens, Scott H. and Hadiyanto, Indonesia: Coalbed Methane Indicators and Basin Evaluation, in SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, October 18-20, 2004, SPE 88630. Bruce, Cassel, et. al., 2012, Proximate Analysis of Coal and Coke Using the ST 8000 Simultaneous Thermal Analyzer, Berry College: GA USA.

Forrester, C., 2005, Methods of Analysis of Coal in India. Fellow of Institute of Fuel. Manning, Carmen S., et. al., 2011, An Alternative Method for Estimating Gas In Place Values for CBM Wells, in CSPG CSEG CWLS Convention, 2011. Rao, V. Gopala and Chakraborty, R. N., Application of Geophysical Well-Logs in Coal bed Methane Prospect Evaluation, HLS Asia Ltd. Rai, D. K., et. al., 2004, Evaluation of Coal Bed Methane through Wire Line Logs Jharia field: A Case Study, in 5th Conference & Exposition on Petroleum Geophysics, India. Levine, J.R., 1991, The Impact of Oil Formed During Coalification on Generation and Storage of Natural Gas in Coalbed Reservoir Systems, in Coalbed Methane Symposium, Tuscaloosa, Alabama, 1991. Kuuskraa, V.A. and Brandenburg, C.F., 1989, Coalbed Methane Sparks a New Energy Industry, in Oil & Gas J., October 1989. Burkett, W.C., McDaniel, R., and Hall, W.L., 1991, The Evaluation and Implementation of a Comprehensive Production Water Management Plan, in Coalbed Methane Symposium, Tuscaloosa, Alabama, 1991. Aminian, K., Coalbed Methane –Fundamental Concepts, Petroleum & Natural Gas Engineering Department, West Virginia University. Ayers, W.B. and Kelso, B.S., 1989, Knowledge of Methane Potential for Coalbed Resources Grows, But Needs More Study in Oil & Gas J., October 1989. Rogers, Rudy, et. al., 2007, Coalbed Methane: Principles and Practices, Second Edition (Courtesy of Halliburton), Starkville: Oktibbeha Publishing. Gregg, S.J. and Pope, M.I., 1959, Fuel. Hewitt, J.L. 1984. Geologic Overview, Coal, and Coalbed Methane Resources of the Warrior Basin-Alabama and Mississippi, in Coalbed Methane Resources of the United States: American Association of Petroleum Geologists Studies in Geology. Barzandji, O.H., et. al., 2000, Combination of Laboratory Experiments and Field Simulations On The Improvement of Coalbed Methane Production By Carbon Dioxide Injection, from Delft University of Technology in Second International Methane Mitigation Conference, Novosibirk, Russia, 2000.


Greb, Stephen F., et. al., 2010, Storing and Using CO2 for Enhanced Coalbed Methane Recovery in Unmineable Coal Beds of the Northern Appalachian Basin and Parts of the Central Appalachian Basin. Mavor, M.J., Gunter, W.D. Gunter, and Robinson, J.R., 2004, Alberta Multiwall Micro-Pilot Testing for CBM Properties, Enhanced Methane Recovery and CO2 Storage Potential. SPE 90256. Advanced Resources International, 1998, Enhanced Coalbed Methane Recovery: Worldwide Application and CO2 Sequestration Potential,

165

Arlington, Virginia USA. Hunt, A.M. dan Steele, D.J., 1991, Coalbed Methane Development in the Northern and Central Appalachian Basins –Past, Present, and Future, in Coalbed Methane Symposium, Tuscaloosa, Alabama, 1991. Weatherall, Glyn, et. al., 2014, Interval Pressure Transient Test and Stress Testing in Coal Bed Methane Wells Using Dual Packer Formation Tester: Case Studies from Indonesia, in Offshore Technology Conference, Kuala Lumpur, Malaysia, March 25-28, 2014.

166


Studi Laboratorium Terhadap Tegangan Antar Muka Sistem Minyak-CO2 pada Kondisi Reservoir A Laboratory Study on the Interfacial Tension of Oil-CO2 System at Reservoir Conditions M. Abdurrahman1 dan A.K. Permadi2 [email protected]; [email protected] 1Universitas Islam Riau, Jl. Kaharuddin Nasution No. 113, Pekanbaru, Riau; 2Institut Teknologi Bandung, Jl. Ganesha 10, Bandung 40132, Indonesia Abstrak Dua sebab utama turunnya produksi minyak nasional adalah keadaan lapangan yang sudah tua dan tekanan yang terus menurun. Sementara itu, tahap produksi umumnya masih didominasi oleh tahap primer dan sekunder. Dengan demikian, diperlukan metode lanjutan, yaitu metode enhanced oil recovery (EOR), untuk meningkatkan perolehan minyak. Metode tersebut di antaranya adalah injeksi kimia, gas, atau injeksi uap. Injeksi gas merupakan metode yang sudah matang dan telah terbukti dapat meningkatkan perolehan minyak. Indonesia memiliki sejumlah lapangan gas dengan kandungan CO2 yang tinggi di sejumlah wilayah kerja. Sumber gas CO2 tersebut sangat berpotensi untuk digunakan dalam metode injeksi gas dalam rangka meningkatkan perolehan minyak. Studi yang disajikan dalam makalah ini bertujuan untuk menentukan tegangan antar muka (interfacial tension, IFT) antara minyak dan gas CO2 melalui eksperimen di laboratorium pada temperatur 40oC, 60oC, dan 80oC. Tekanan yang diberikan berada pada kisaran 700 psi sampai 1800 psi. Melalui penelitian ini, dapat diketahui besarnya penurunan tegangan antar muka pada kondisi reservoir. Tegangan antar muka ditentukan dengan cara perhitungan melalui metode pendant drop. Sampel minyak yang digunakan dalam penelitian ini diambil dari salah satu lapisan yang berada di Formasi Air Benakat, Cekungan Sumatera Selatan. Hasil studi menunjukkan bahwa tegangan antar muka CO2 dan sampel minyak turun secara signifikan seiring dengan kenaikan tekanan. Pada temperatur 40oC terjadi penurunan tegangan antar muka dari 23,16 dyne/cm menjadi 0,83 dyne/cm. Pada temperatur 60oC terjadi penurunan tegangan antar muka dari 24,25 dyne/ cm menjadi 2,52 dyne/cm. Pada temperatur 80oC terjadi penurunan tegangan antar muka dari 25,88 dyne/ cm menjadi 3,33 dyne/cm. Kenaikan tekanan menyebabkan penurunan tegangan antar muka dan sebaliknya kenaikan temperatur menyebabkan kenaikan tegangan antar muka. Studi semacam ini sangat penting dilakukan sebelum melakukan injeksi CO2 di lapangan yang diinginkan. Tegangan antar muka sangat erat kaitannya dengan parameter penting lainnya seperti wettability, tekanan kapiler, dan dispersi gas. Dengan mengetahui besarnya penurunan tegangan antar muka maka dapat diketahui perubahan yang terjadi pada ketiga paremeter diatas. Perubahan parameter-parameter tersebut akan memberikan kontribusi yang sangat signifikan terhadap mekanisme penambahan produksi minyak melalui injeksi gas CO2. Kata Kunci: Tegangan antar muka, injeksi CO2, peningkatan perolehan, metode pendant drop. Abstract Two major reasons for the national oil production to decline is the maturity of the fields and the continuously declining pressure. In the meantime, the primary and secondary phases are still dominating the production stage. As a result, an enhanced oil recovery (EOR) method is required to improve the oil recovery. The available methods are chemical, gas, or steam injections. Gas injection is a mature method and proved to be able to improve oil recovery. Indonesia is operating a number of gas fields with high CO2 content. This abundant source of CO2 is prospective to be used for gas injection in order to improve oil recovery. This study is aimed to determine the interfacial tension between oil and CO2 through a laboratory experiment at temperatures of 40oC, 60oC, and 80oC. The pressure is given at the range of 700 psi to 1800 psi. Through the study the reduction in interfacial tension at reservoir condition can be known. The interfacial

167

168


tension is determined by calculations through the use of pendant drop method. The oil samples were taken from a reservoir within Air Benakat Formation lying in South Sumatera Basin. The result of the study shows that the interfacial tension of CO2 and the oil sample decreases significantly as the pressure increases. At the temperature of 40oC the interfacial tension decreases from 23.16 dyne/cm to 0.83 dyne/cm. At the temperature of 60oC the interfacial tension decreases from 24.25 dyne/cm to 2.52 dyne/cm. At the temperature of 80oC the interfacial tension decreases from 25.88 dyne/cm to 3.33 dyne/cm. The increase in pressure causes the decrease in the interfacial tension and inversely the increase in temperature causes the increase in the interfacial tension. This kind of study should necessarily be conducted prior to conducting CO2 injection in a desired field. The interfacial tension is strongly related to the other pertinent parameters such as wettability, capillary pressure, and gas dispersion. By knowing the reduction in the interfacial tension then the change in the three important parameters can also be known. The change in the mentioned parameters will provide significant contribution to the mechanism of improving oil production by CO2 injection. Keywords: interfacial tension, CO2 injection, enhanced recovery, pendant drop method.

I. PENDAHULUAN

Permasalahan di lapangan

Tinjauan ringkas tentang CO2-EOR

Lapangan minyak yang telah diproduksi melalui tahap primer dalam kurun waktu yang cukup lama tanpa melakukan langkah-langkah pemeliharaan tekanan (pressure maintenance) akan berakibat tekanan reservoir turun menjadi sangat rendah. Jika keadaan ini tidak diatasi maka produksi minyak dari lapangan tersebut akan turun menjadi sangat rendah pula. Dalam keadaan demikian, perlu dilakukan upaya agar produksi minyak dapat ditingkatkan kembali. Menurut Laporan SKK Migas Tahun 2015, metode primer dan sekunder masih menyisakan jumlah hidrokarbon yang sangat signifikan di banyak lapangan minyak di Indonesia. Sebenarnya, berbagai upaya telah dilakukan untuk mempertahankan laju alir produksi primer tersebut pada saat ini. Namun, laju penuruan produksi tidak dapat dipertahankan secara signifikan sehingga diperlukan langkah lebih lanjut, yaitu menerapkan metode peningkatan perolehan tahap lanjut, untuk meningkatkan perolehan minyak dari lapangan yang sudah tua (mature) atau jika tekanan reservoir sudah sangat menurun (depleted) sesuai dengan potensi yang ada.

Di antara berbagai metode enhanced oil recovery (EOR) yang telah di implementasikan secara luas adalah injeksi termal dan injeksi gas. Injeksi termal telah terbukti dapat meningkatkan perolehan minyak di beberapa lapangan utama di dunia seperti yang terjadi di Canada, Amerika, dan Indonesia (Koottungal, 2014). Metode ini digunakan untuk menurunkan viskositas minyak yang tinggi pada kondisi reservoir (Pearce and Megginson, 1991). Metode EOR berupa injeksi gas yang telah dikenal dan terbukti berhasil meningkatkan perolehan minyak adalah injeksi gas menggunakan gas karbon dioksida (CO2). Metode ini dikenal sebagai metode CO2-EOR yang telah terbukti meningkatkan perolehan minyak dengan sangat signifikan seperti yang terjadi di Lapangan Sacroc Unit, Dollarhide, Bell Creek, dan Camurlu (Gill, 1982; Bellavance, 1996; Gorecki dkk, 2012; Gondiken, 1987). Telah diketahui bahwa dalam rangka peningkatan perolehan minyak, metode CO2-EOR dapat diterapkan baik pada minyak berat maupun pada minyak ringan. Injeksi CO2 tercampur (miscible) telah terbukti memberikan perolehan dalam kisaran 10-20% dari kandungan minyak awal (original oil in-place, OOIP). Jika tekanan reservoir sudah berkurang maka injeksi CO2 tidak tercampur (immiscible) dapat dilakukan. Metode ini telah terbukti dapat meningkatkan perolehan minyak yang cukup signifikan yaitu dalam kisaran 5-10% dari kandungan minyak awal (Lake, 1989).

Solusi saat ini dan solusi yang diusulkan Solusi jangka pendek dalam rangka upaya untuk meningkatkan atau sekurang-kurangnya mempertahankan laju produksi minyak adalah dengan melakukan berbagai cara termasuk melakukan stimulasi sumur, membuat sumur sisipan, melakukan injeksi air untuk memelihara tekanan, melakukan perforasi ulang, mengganti

Studi Laboratorium Terhadap Tegangan Antar Muka Sistem Minyak-CO2 pada Kondisi Reservoir (M. Abdurrahman dan A.K. Permadi)

metode pengangkatan buatan, dan lain-lain. Upaya-upaya tersebut pada akhirnya tidak mampu untuk terus mempertahankan produksi sehingga diperlukan metode peningkatan perolehan lanjut. Salah satu metode lanjut untuk meningkatkan perolehan atau enhanced oil recovery (EOR) yang sudah terbukti dapat meningkatkan produksi minyak adalah injeksi gas menggunakan gas CO2. Keberadaan gas CO2 di udara sangat dominan dan telah terbukti memberikan kontribusi besar terhadap pemanasan global (Howard dkk, 2000). Gas CO2 dapat dihasilkan dari aktivitas produksi minyak dan gas bumi. Gas CO2 dapat pula dihasilkan dari kegiatan industri seperti pabrik semen, industri petrokimia, pabrik baja, pembangkit listrik batubara, dan lain-lain (Dipietro, 2012). Di samping dapat memberikan peningkatan perolehan minyak, melakukan injeksi gas CO2 ke dalam reservoir minyak juga dapat membantu mengurangi terlepasnya gas CO2 ke udara. Dengan demikian, injeksi gas CO2 memberikan nilai tambah tersendiri dalam upaya pelestarian lingkungan hidup. Aktivitas tersebut dikenal dengan sebutan CO2 sequestration and utilization yang telah banyak dilakukan di berbagai negara maju. Gas CO2 dapat tercampur dengan minyak pada tekanan tertentu dan jika tekanan ini tercapai dapat memberikan perolehan minyak yang sangat signifikan (Lake, 1989). Namun, jika tekanan tercampur tidak dapat dicapai, tambahan produksi minyak masih dapat diperoleh melalui mekanisme injeksi tak tercampur termasuk oil swelling, penurunan viskositas, penurunan densitas, gas drive, dan penurunan tegangan antar muka antara CO2 dan minyak. Oleh karena itu, sangat penting untuk mengetahui tegangan antar muka yang terjadi pada kondisi reservoir jika gas CO2 diinjeksikan ke dalam reservoir. Jika tegangan antar muka CO2 dan minyak dapat diturunkan maka tekanan kapiler akan menurun sehingga minyak yang terperangkap di dalam pori-pori batuan menjadi lebih mudah untuk mengalir menuju lubang sumur. Selain itu, untuk reservoir yang terdiri dari batuan karbonat maka keberadaan gas CO2 akan mengakibatkan perubahan sifat kebasahan batuan (wettability alteration). Dalam hal ini, kehadiran gas CO2 mengakibatkan batuan yang semula bersifat oil

169

wet berubah menjadi intermediate wet sehingga membuat minyak lebih mudah mengalir. Namun, penurunan tegangan antar muka CO2 dan minyak dapat kurang sempurna apabila terdapat keadaan di dalam reservoir yang kurang menguntungkan. Salah satunya adalah dispersi gas. Jika jumlah gas yang terdispersi di dalam reservoir cukup banyak maka jumlah gas CO2 yang berkontak dengan minyak menjadi lebih sedikit sehingga penurunan tegangan antar muka CO2 dan minyak tidak maksimal. Beberapa studi untuk mengkaji besaran tegangan antar muka CO2 dan minyak di laboratorium telah dilakukan oleh El-Sharkawy dkk (1992), Rao (1997), dan Sarapardeh dkk (2014). Tujuan studi dan hasil yang di harapkan Studi ini bertujuan untuk melakukan pengukuran besaran tegangan antar muka yang terjadi antara CO2 dan minyak pada berbagai harga tekanan dan temperatur pada kondisi reservoir dan selanjutnya mengkaji perubahan tegangan antar muka antara kedua fluida. Studi ini sangat penting dilakukan untuk mengetahui pengaruh tekanan dan temperatur terhadap perubahan tegangan antar muka antara kedua fluida. Untuk mendapatkan perolehan minyak yang maksimal maka tegangan antar muka harus diturunkan sebesar mungkin. Selain itu, hasil pengukuran tegangan antar muka dapat memberikan informasi tentang mekanisme yang terjadi, yaitu apakah pendesakan bersifat tercampur (miscible) atau tidak tercampur (immiscible). Jika harga tegangan antar muka sama dengan nol maka mekanisme yang terjadi adalah pendesakan tercampur dan jika harga tegangan antar muka lebih besar dari nol maka mekanisme yang terjadi adalah pendesakan tidak tercampur. II. METODOLOGI Studi ini dilakukan dengan cara melakukan eksperimen di laboratorium dengan menggunakan peralatan yang telah baku untuk menentukan tegangan antar muka sistem duafluida yang dalam hal ini berupa sistem yang terdiri dari gas CO2 dan minyak. Tegangan antar muka dalam studi ini ditentukan dengan cara perhitungan melalui metode pendant drop

170


menggunakan peralatan goniometer yang telah dilengkapi dengan sebuah view cell khusus untuk kondisi tekanan dan temperatur tinggi. Gas CO2 yang digunakan mempunyai tingkat kemurnian 99,99%. Sampel minyak yang digunakan berasal dari Formasi Air Benakat di Cekungan Sumatera Selatan. Sampel minyak tersebut mempunyai API gravity 41,38 dengan sifat fisik dan komposisi seperti ditunjukkan pada Tabel 1 dan 2. Tekanan yang diberikan mulai dari 700 psi sampai 1800 psi dengan tiga harga temperatur yaitu 40oC, 60oC, dan 80oC. Harga tekanan dan temperatur tersebut diambil untuk menggambarkan keadaan reservoir yang sebenarnya. Tahapan studi meliputi tiga kelompok kegiatan yaitu: 1) pra-eksperimen, 2) eksperimen, dan 3) pasca-eksperimen. Tahap pra-eksperimen meliputi kegiatan yang terkait dengan kalibrasi peralatan, pembersihan dan pengeringan tubing line yang akan dilewati oleh minyak dan gas CO2 masing-masing menggunakan toluene dan gas nitrogen. Kegiatan selanjutnya adalah pembersihan view cell dengan menggunakan vacuum pump dan kemudian pemanasan view cell sesuai dengan temperatur yang diinginkan. Sedangkan tahap eksperimen meliputi kegiatan pengaliran gas CO2 menggunakan isco pump ke dalam view cell yang sudah dipanaskan sebelumnya. Kegiatan eksperimen selanjutnya adalah pengukuran tegangan antar muka yang dilakukan sebanyak tiga kali untuk setiap satu set harga tekanan dan temperatur. Penentuan tegangan antar muka dilakukan melalui perhitungan dengan menggunakan program yang tersedia dalam paket peralatan di mana harga tegangan antar muka yang terhitung tersebut ditampilkan secara langsung pada layar komputer. Tahap ketiga, yaitu pasca-eksperimen meliputi kegiatan pembersihan tubing line kembali dengan menggunakan prosedur dan bahan yang sama seperti pada tahap praeksperimen. Spesifikasi view cell dan jarum yang digunakan adalah sebagai berikut. View cell dapat bertahan hingga tekanan sebesar 3000 psi dan hingga temperatur sebesar 300oC. Tebal kaca view cell adalah 10 mm dengan ukuran diameter 30 mm. Diameter luar (outside diameter) dari jarum adalah 0,91 mm dengan panjang jarum 50 mm. Setelah tekanan dan temperatur yang diinginkan berada dalam keadaan stabil, isco

pump memompakan air ke dalam chamber yang berisi sampel minyak dengan kecepatan antara 0,1 cc – 0,5 cc per menit hingga minyak mengalir secara perlahan sampai di ujung jarum yang ada di dalam view cell. Agar minyak tetap tergantung di ujung jarum, tekanan isco pump harus dijaga selalu lebih besar sedikit dari tekanan di dalam view cell. Selain itu, kecepatan alir minyak menuju ke ujung jarum dapat diatur secara manual dengan menggunakan control valve. Untuk mengantisipasi aliran balik (flowback) dari view cell menuju chamber digunakan flow back pressure device yang dipasang di antara view cell dan chamber. Skematik peralatan yang digunakan dapat dilihat pada Gambar 1. III. HASIL EKSPERIMEN Eksperimen yang dilakukan dalam studi ini menghasilkan data yang berupa besaran tegangan antar muka antara CO2 dan minyak pada kondisi reservoir. Tekanan yang diberikan untuk setiap temperatur mempengaruhi besaran tegangan antar muka yang diperoleh. Dalam hal ini, peningkatan tekanan mengakibatkan penurunan tegangan antar muka. Hasil pengukuran tegangan antar muka antara CO2 dan minyak dalam studi ini dapat dilihat pada Gambar 2 sampai dengan Gambar 4 berikut. Seperti terlihat pada Gambar 2, pada temperatur 40oC terjadi penurunan tegangan antar muka dari 23,16 dyne/cm pada tekanan 700 psia menjadi 0,83 dyne/cm pada tekanan 1200 psia. Sedangkan pada Gambar 3 terlihat bahwa pada temperatur 60oC terjadi penurunan tegangan antar muka dari 24,25 dyne/cm pada tekanan 800 psia menjadi 2,52 dyne/cm pada tekanan 1800 psia. Selanjutnya, Gambar 4 menunjukkan bahwa pada temperatur 80oC terjadi penurunan tegangan antar muka dari 25,88 dyne/cm pada tekanan 700 psia menjadi 3,33 dyne/cm pada tekanan 1800 psia. Disamping menyebabkan penurunan tegangan antar muka, tekanan yang diberikan juga mengakibatkan perbedaan ukuran droplet minyak. Peningkatan tekanan membuat volume minyak yang tergantung di ujung jarum menjadi lebih kecil. Gambar 5 sampai dengan Gambar 7 berikut menunjukkan pengaruh tekanan terhadap ukuran droplet minyak yang tergantung di ujung jarum.


IV. PEMBAHASAN DAN DISKUSI Tekanan terbukti berpengaruh sangat signifikan terhadap penurunan tegangan antar muka antara CO2 dan minyak. Data hasil eksperimen dalam studi ini menunjukkan bahwa kenaikan tekanan yang diberikan dapat menurunkan tegangan antar muka antara CO2 dan minyak secara drastis terutama pada temperatur rendah. Secara common sense, kenaikan tekanan menyebabkan densitas CO2 meningkat dan jika kenaikan tekanan terus berlangsung maka harga densitas CO2 dapat mendekati harga densitas minyak. Dengan kata lain, perbedaan densitas antara CO2 dan minyak menjadi makin kecil. Dalam keadaan perbedaan densitas antara dua fluida yang berkontak kecil maka tegangan antar muka antara kedua fluida yang berkontak tersebut relatif lebih rendah. Temperatur memberikan pengaruh sebaliknya terhadap tegangan antar muka CO2 dan minyak di mana kenaikan temperatur mengakibatkan peningkatan tegangan antar muka antara CO2 dan minyak. Dapat dipahami bahwa kenaikan temperatur menyebabkan CO2 lebih sulit untuk terlarut di dalam minyak. Di samping itu, kenaikan temperatur menyebabkan penurunan densitas CO2 pada tekanan yang sama. Dengan kata lain, diperlukan tekanan yang lebih tinggi untuk meningkatkan densitas CO2 pada temperatur yang lebih tinggi. Pada tekanan dan temperatur yang digunakan pada eksperimen dalam studi ini, terlihat bahwa semakin besar perbedaan densitas antara CO2 dan minyak mengakibatkan tegangan antar muka semakin besar. Dengan demikian, kenaikan temperatur akan mengakibatkan tegangan antar muka CO2 dan minyak menjadi lebih tinggi. Observasi lanjut terhadap besaran tegangan antar muka pada ketiga harga temperatur yang digunakan menunjukkan bahwa tegangan antar muka yang terjadi pada temperatur 40oC menurun sampai mendekati harga nol. Hal ini menandakan bahwa pada temperatur rendah mekanisme miscible atau near-miscible lebih mudah untuk terjadi bahkan pada tekanan yang relatif lebih rendah. Sedangkan tegangan antar muka pada kedua temperatur lainnya yang lebih tinggi, yaitu pada temperatur 60oC dan 80oC, tegangan antar muka dapat mendekati harga nol pada tekanan yang jauh lebih tinggi. Dengan demikian, pada harga tekanan maksimal yang

171

diberikan pada eksperimen ini, mekanisme yang terjadi adalah immiscible. Selanjutnya, melalui observasi visual, diperoleh informasi tentang pengaruh tekanan dan temperatur terhadap ukuran droplet minyak yang menggantung di ujung jarum. Dari observasi tersebut terlihat bahwa kenaikan tekanan mengakibatkan ukuran droplet minyak menjadi lebih kecil. Perubahan volume droplet ini terutama disebabkan oleh proses ekstraksi komponen ringan dari sampel minyak yang digunakan. Kenaikan tekanan selanjutnya akan mengakibatkan keadaan di mana hanya komponen berat yang tertinggal di droplet. Jika keadaan ini terus berlangsung maka akan mendekati kondisi tercampur (miscible) atau kondisi hampir tercampur (near miscible). V. KESIMPULAN DAN SARAN Hasil studi ini memberikan beberapa kesimpulan sebagai berikut: 1. Pada kondisi reservoir, tegangan antar muka CO2-minyak sangat dipengaruhi oleh besaran tekanan dan temperatur. 2. Kenaikan tekanan mengakibatkan penurunan tegangan antar muka CO2-minyak. Sebaliknya, kenaikan temperatur dapat menyebabkan kenaikan tegangan antar muka CO2-minyak. 3. Kenaikan tekanan mengakibatkan perbedaan densitas antara CO2 dan minyak menjadi lebih kecil. Mekanisme tersebut dapat menyebabkan penurunan tegangan antar muka CO2-minyak. 4. Kenaikan temperatur mengakibatkan perbedaan densitas antara CO2 dan minyak menjadi lebih besar. Fenomena tersebut dapat menyebabkan penurunan tegangan antar muka CO2-minyak menjadi lebih sulit pada temperatur yang lebih tinggi. 5. Mekanisme tercampur (miscible) antara CO2 dan minyak, yang ditandai oleh tegangan antar muka yang mendekati harga nol, lebih mudah untuk terjadi pada temperatur yang lebih rendah. Sedangkan pada temperatur yang lebih tinggi, diperlukan tekanan yang jauh lebih tinggi agar tegangan antar muka mendekati harga nol. Pada kondisi di mana tegangan antar muka lebih besar dari harga nol, mekanisme yang terjadi adalah tak tercampur (immiscible).

172


UCAPAN TERIMA KASIH Para penulis mengucapkan terima kasih kepada Prof. W.S. Bae dari Sejong University, Korea, dan Prof. I.W. Kim dan Prof. J. H. Lee dari Konkuk University, Korea, atas bantuan peminjaman peralatan eksperimen dan diskusi intensif selama studi ini dilakukan. Selain itu, ucapan terima kasih juga disampaikan kepada Universitas Islam Riau atas bantuan dan dukungan yang diberikan. REFERENSI Bellavance, J.F.R., 1996. “Dollarhide Devonian CO2 Flood: Project Performance Review 10 Years Later”, Paper SPE 35190-MS presented at Permian Basin Oil and Gas Recovery Conference, 27-29 March, Midland, Texas. http://dx.doi. org/10.2118/35190-MS. DiPietro, P., Balash, O., Wallace, M., 2012. “A Note on Sources of CO2 Supply for Enhanced Oil Recovery Operations”, SPE Journal of Economic and Management (Paper EM-1111-0002). El-Sharkawy, A.M., Poettmann, F.H., Christiansen, R.L., 1992. “Measuring Minimum Miscibility Pressure: Slim Tube or Rising Bubble Method?” Paper SPE-24114-MS presented at SPE/ DOE Enhanced Oil Recovery Symposium, 22-24 April, Tulsa, Oklahoma. http://dx.doi. org/10.2118/24114-MS. Gill, T.E., 1982. “Ten Years of Handling CO2 for SACROC Unit”, Paper SPE 11162-MS presented at SPE Annual Technical Conference and Exhibition, 26-29 September, New Orleans, Louisiana. http://dx.doi.org/ 10.2118/11162-MS.

Gorecki, C.D., Hamling, J.A., Ensrud, J., Steadman, E.N., Harju, J.A., 2012. “Integrating CO2 EOR and CO2 Storage in the Bell Creek Oil Field”, Paper SPE 151476 presented at Carbon Management Technology Conference, 7-9 February, Orlando, Florida. http://dx.doi. org/10.7122/151476-MS. Gondiken, S., 1987. “Camurlu Field Immiscible CO2 Huff and Puff Pilot Project”, Paper SPE 15749-MS presented at Middle East Oil Show, 7-10 March, Bahrain. http://dx.doi.org /10.2118/15749-MS. Howard, H., Baldur, E., Olav, K., 2000. “Capturing Greenhouse Gases”, https://sequestration.mit. edu/pdf/SciAmer.pd. [12 September 2016] Koottungal, L., 2014. 2014 “Worldwide EOR Survey”, Oil & Gas Journal, Vol. 112, No. 5. Lake, L.W., 1989. Enhanced Oil Recovery, Prentice Hall, New Jersey. Pearce, J.C. and Megginson, E.A., 1991. “Current Status of Duri Steamflood Project Sumatra, Indonesia”, Paper SPE 21527-MS presented at the SPE International Thermal Operations Symposium, 7-8 February, Bakersfield, California. http://dx.doi.org/10.2118/ 21527-MS Rao, D.N., 1997. “A New Technique of Vanishing Interfacial Tension for Miscibility Determination”, Fluid Phase Equilibria, Vol. 139, Hal. 311-324. SKKMigas, 2015. Laporan Tahunan 2015, SKKMigas, Jakarta. Sarapardeh, A.H., Ayatollahi, S., Ghazanfari, M.H., Masihi, M., 2014. “Experimental Determination of Interfacial Tension and Miscibility of the CO2Crude Oil System; Temperature, Pressure, and Composition Effects”, Journal of Chemical and Engineering Data. Vol. 59, Hal. 61-69.


LAMPIRAN Tabel 1. Sifat Fisik Minyak dan Kondisi Reservoir.

Tabel 2. Komposisi Minyak.

Gambar 1. Skematik diagram eksperimen tegangan antar muka CO2-minyak.

173

174


Gambar 2. Tegangan antar muka CO2 dan minyak pada temperatur 40oC.




175

Gambar 5a. Oil droplet pada tekanan 700 psia dan temperatur 40oC.

Gambar 5b. Oil droplet pada tekanan 1000 psia dan temperatur 40oC.





176


A Successful Innovative Pilot Project of Natural Dumpflood - Alpha Sand in Oleander Field Central Sumatra Basin Keberhasilan proyek inovasi Natural Dumpflood di Lapangan Minyak Oleander, Reservoir Alpha, Cekungan Sumatera Tengah Ade Fadli1, Dedek Priscilla2 dan Muhamad Irfan3 [email protected] (1)(2)(3)Chevron Pacific Indonesia Komplek PT Chevron Pacific Indonesia (CPI), Rumbai Main Office Room-358. Abstract

The recent downturn in oil price has impacted capital expenditure and risk appetite. Strong economic justification is required for a project to be executed, where projects with minimum capital investment and low risk are highly preferable. Addressing this challenge in CPI operating area; a natural dumpflood has been successfully implemented in Oleander Field, an oil field under primary recovery in the Central Sumatera Basin. Unlike a traditional surface water injection, reservoir target is flooded by utilizing pressure contrast between two reservoirs to create natural cross flow, therefore eliminating the need for water treatment facilities, pipelines and surface injection pumps. Recent surveillance in newly drilled wells has confirmed that the current reservoir pressure of Alpha Sand is approximately 35% of the original reservoir pressure. This 125 acre sand-stone reservoir is designated as natural dumpflood target after evaluating remaining reserves, OOIP, rock properties, and connectivity. Situated 1000 ft above Alpha Sand, a non-productive, high pressure reservoir called Bravo Sand is selected as water-source for natural dumpflood. An idle well located at the flank was converted to injection well via a low cost workover to enable the natural flooding. Fluid compatibility testing was undertaken. Post injection surveillance was established on both injector and adjacent producers to monitor pressure response. This paper present the concept, selection process, challenges and best practices of natural dumpflood Pilot Project. Significant production gains have been observed a few months after initiating the dumpflood. With minimal investment and short initiation times, this pilot has been economically viable and has the potential to be implemented in other fields. Other potential applications include using a dumpflood to pilot a larger scale waterflood in order to de-risk a large investment in a low oil price environment. Keywords: Surveillance, Waterflood, Natural Dumpflood, Cross Flow.

Abstrak Penurunan harga minyak akhir-akhir ini berdampak negatif terhadap proyek waterflood di seluruh dunia. Pertimbangan keekonomian menjadi salah satu faktor penentu, dimana investasi minimum dan resiko yang kecil adalah kondisi yang diharapkan untuk sebuah proyek yang akan dieksekusi. Dalam merespon tantangan ini di area operasi CPI, sebuah proyek natural dumpflood telah berhasil diimplementasikan di Lapangan Oleander, sebuah lapangan minyak di Cekungan Sumatera Tengah yang saat ini masih berada pada tahapan primary recovery. Berbeda dengan metode injeksi air pada umumnya, pada metode natural dumpflood ini, target reservoir diinjeksi dengan menggunakan air yang berasal dari aliran antar-lapisan yang timbul secara alami sebagai implikasi dari perbedaan tekanan antara dua reservoir. Sehingga dapat disimpulkan, metode injeksi ini tidak memerlukan fasilitas pengolahan air, pipa, dan pompa injeksi seperti metode injeksi air pada umumnya. Inisiatif ini didasari hasil survey tekanan reservoir terkini dari beberapa sumur yang baru dibor di Lapangan Oleander. Data tersebut mengkonfirmasi penurunan tekanan reservoir yang sangat signifikan, khususnya pada Reservoir Alpha yang saat ini memiliki tekanan berkisar 35% dari kondisi awal. Reservoir seluas 125 acre ini dipilih menjadi target untuk natural dumpflood setelah mempertimbangkan beberapa faktor antara lain: OOIP, evaluasi cadangan minyak tersisa, karakteristik dan konekvifitas reservoir. Reservoir Bravo dipilih sebagai reservoir sumber air untuk diinjeksikan ke Reservoir Alpha karena masih memiliki

177

178


tekanan yang relative tinggi. Reservoir ini merupakan reservoir yang tidak produktif dan terletak sekitar 1000 ft di atas Reservoir Alpha. Untuk menginisiasi proses injeksi alami, sebuah sumur minyak yang sudah lama tidak berproduksi dikonversi menjadi sumur injeksi melalui pekerjaan ulang berbiaya relatif rendah. Uji kompatibilitas fluida dilakukan untuk mengantisipasi efek negatif dari percampuran fluida yang berasal dari dua reservoir berbeda. Pemantauan pascainjeksi juga direncanakan di sumur injeksi dan sumur produksi disekitarnya untuk memonitor progress dari natural dumpflood. Makalah ini menampilkan konsep, proses seleksi, tantangan serta pembelajaran dari proyek percobaan natural dumpflood di Lapangan Oleander. Dengan kenaikan produksi yang cukup signifikan setelah beberapa bulan pascainjeksi, ditambah dengan investasi yang minimum dan waktu inisiasi yang relatif cepat, proyek ini telah terbukti berhasil secara keekonomian dan dapat diaplikasikan di lapangan-lapangan minyak lain. Metode ini juga sangat tepat diaplikasikan sebagai percobaan awal pada proyek water flood berskala besar untuk meminimalisir resiko investasi pada kondisi harga minyak yang rendah. Kata Kunci: Survei tekanan reservoir, Injeksi Air, Natural Dumpflood, Aliran antar-lapisan.

I. INTRODUCTION

III. METHODOLOGY

Oleander field is located at Central Sumatra Basin (CSB) under Rokan Block PSC. It was discovered in 1997, and first development drilling began in 2001. The field reached its peak production in 2004 (~5,000 BOPD) after completing progressive amount of drilling activities targeting Sierra Formation. Recent surveillance (RFT) in newly drilled wells in 2015 confirmed that reservoir pressures of 3 productive zones in Sierra Formation are significantly depleted. These 3 depleted zones hold approximately 70% of total field’s OOIP and used to be major contributor for oil production in Oleander field. Sufficient evidence showed that the significant pressure depletion was caused by the huge amount of fluid withdrawn from these depleted reservoirs since 2003.

A low-cost pressure maintenance effort called natural dumpflood (NDF) was suggested as an alternative to waterflood. Unlike a traditional surface water injection, reservoir target is flooded by utilizing pressure contrast between two reservoirs to create natural cross flow, therefore eliminating the need for water treatment facilities, pipelines, surface injection pumps and, hence minimize capital investment. This pressure maintenance method was selected after evaluating latest RFT data in which, not only confirmed that Oleander field has depleted productive reservoirs, but also exposed the existence of high pressure non-productive reservoir which further considered as water source zone.

II. PROBLEM STATEMENT With substantial pressure depletion issue, the strategy to increase production becomes more challenging where in this case the deliverability of producer wells is negatively affected. An internal study concluded that reservoir pressure maintenance was needed to increase production in Oleander field, and one of the solutions appears to be waterflooding. However, considering the field location is in remote area and there is no existing surface injection facility in Oleander field, this option is forecasted to cost a large initial investment and require longer setup time to complete the facility which ultimately will hurt project economics.

Reservoir Selection Process The depleted reservoirs as shown in Figure 1 are defined as Alpha, Delta and Echo Sand. The average depth of these sands is approximately 5400 ft. Recent RFT data revealed the current reservoir pressure of these sands is around 550 psi. It has depleted significantly from its original pressure around 1600 psi. Situated approximately 1000 ft above those 3 depleted zones, lies Bravo Sand, a nonproductive zone with reservoir pressure around 1200 psi. This particular reservoir still remains at original state as no depletion since the first development of Oleander field. NDF relies heavily on pressure difference between the source and the target zone. Aside from that, the distance between reservoirs also plays an important role. It will create hydrostatic

A Successful Innovative Pilot Project of Natural Dumpflood - Alpha Sand in Oleander Field Central Sumatra Basin (Ade Fadli, Dedek Priscilla dan Muhamad Irfan)

pressure, thus increase injection pressure to the target zone. Technically said, the greater the distance, the more cross flow rate will be created. As the project was aimed to evaluate the viability of pressure maintenance effort, the best of the 3 depleted reservoirs was selected as the pilot target zone to make distinct post injection monitoring, for example pressure response, injection rate allocation, and incremental production. Instead of injecting the entire cross flow rate to all depleted sands, focused injection to single target zone more likely to yield faster flood response. After evaluating the following key parameters; reservoir properties, lateral connectivity, recoverable reserves and surrounding well completion, Alpha Sand was nominated as the pilot target zone. This 125 acre sand-stone reservoir has areal extension across all Oleander field. It has more decent reservoir properties compared with Delta and Echo Sand. The average porosity and permeability of this clean sand are approximately at 24% and 820 md, respectively. In cross section, 40 ft average reservoir thickness appeared uniform at all wells penetrating to this sand, which gives the idea of good reservoir connectivity. In terms of hydrocarbon in place, Alpha Sand is also superior to other depleted zone. In fact, it was actually the largest oil in place contributor, approximately 40% of total field’s OOIP. Another upside of this sand is the existence of open-perforated zone on the corresponding sand across active oil producer wells. This will add further benefit to this initiative in terms of well intervention cost because unnecessary reperforation job for producer-injector alignment can be avoided. Several technical considerations are also taken into account when selecting best water source reservoir for the project. Basically, the preferred water source zone is the one that is able to provide optimum injection rate to the target zone. It should be the zone with higher pressure contrast relative to reservoir pressure of the target zone, decent reservoir properties, and enough fluid in place to guarantee sustainability of injection rate. An ideal water resource is the one that have no compatibility issue, as incompatible fluids can create future problems such as plugging, scaling, emulsion and precipitation. Bravo Sand is seen to have

179

the key qualifications to be a great water source. Aside from having sufficient pressure contrast to target zone, this 80 ft thick, highly conductive, non-productive Sand, also has huge areal extension across the field, which signifying adequate water support. In cross section, the corresponding sand appears to have similar signature, reflecting decent lateral connectivity. In addition, preliminary analysis suggests that fluid compatibility was acceptable, considering both sand were formed from the same formation. Injection Well Selection Process Designated dumpflood wells were selected from existing producer wells. Top priority was given to uneconomic and long idle producer wells in order to minimize oil loss. From technical stand point, these candidate wells have to meet the basic screening criteria for following parameters; well integrity, decent reservoir properties, structural location, proximity to surrounding producer wells and good lateral connectivity. Having those parameters evaluated and crosschecked on every available idle and uneconomic well, well DF1 was identified as the only suitable dumpflood well candidate. The subject well was drilled in 2004, located at the flank structure of Oleander Field below current OWC, and has been idle since 2009 due to uneconomic reason. Acceptable well integrity has been confirmed from CBL data and MIT test. Cumulative production of this directional well is approximately up to 270 MBO. In this particular well, Alpha & Bravo Sand were encountered at depth 3900 ft and 4900 ft, respectively. It has been evaluated to have favorable reservoir properties in terms of porosity, permeability and thickness. The other 2 wells that are also located at the flank structure of Oleander field were easily eliminated from pilot dumpflood candidate since it did not penetrate through Alpha Sand. However, those wells will be considered as future dumpflood candidates depending on pilot result and may require deepening effort. Another advantage that can be taken from this well is the fact that Alpha Sand has existing open perforation at the zone of interest. This will become actual cost saving during well conversion job by eliminating unnecessary re-perforation job.

180


MBAL Simulation Simple material balance simulations were performed to determine the feasibility of natural dumpflood pilot testing. Reservoir model was built using MBAL software by assuming Alpha Sand as homogenous tank. The reservoir properties are summarized in Table 1. These properties were based on analysis of production data from several wells. The first step of simulation was to obtain acceptable history matching. Afterward, forecast scenario was set to calculate the incremental production. To mimic the crossflow rate from Bravo to Alpha Sand, a virtual injection well was added with various injection rates. A simple mass balance concept was used to estimate injection rate. Both analytical and probabilistic approach was used to estimate the deliverability and injectivity of target zone. Figure 2 presents comparison of three production forecast cases: high, low and medium injection rate case. The oil production rates clearly show the benefit of the natural dumpflood. A value of incremental oil rate approximately 30 STB/D can be expected from natural dumpflood. Figure 3 also shows the oil recovery as a function of the injected water volume. The oil recovery estimation based on simulation from natural dumpflooding is about 34%. Economic analysis was done by referring to above forecast data with associated cost approximately $80,000. As predicted, the result was economically attractive with NPV M$ 96 and DPI 2.26 Overall, the pilot flood simulation showed that the natural dumpflood was feasible. The modeling also showed that additional injection rate accelerates oil recovery for Oleander field. Workover Execution The feasibility of NDF for Oleander field was supported by computer simulation results. The next step was to confirm prediction model from simulation with actual pilot testing. A workover was conducted at well DF1 to perforate Bravo Sand interval followed by formation testing & sampling. Testing result was acquired to evaluate reservoir pressure and reservoir deliverability, whereas the sampling was sent for

lab testing for compatibility analysis. The target reservoir, Alpha Sand, was also evaluated for its deliverability by conducting injection test and step rate test. Test result of both sands can be seen in picture below. Based on swab test result, the Productivity Index (PI) and AOF capacity of Bravo Sand are 22 BFPD/psi and 25.700 BFPD, respectively. At the same time, fair injectivity result was obtained from Alpha Sand. Even though the result was not conclusive enough to give the approximation of Injectivity Index (II), Injection behavior at early stage of step rate test at least reflected decent capability of Alpha Sand to receive water injection. Figure 4 shows the post-workover completion of the dumpflood well. It was completed with 3.5” tubing string and annulus packer at depth 3805 ft. as final injection completion. This configuration was meant to eliminate potential exposure from annulus and also give the flexibility to re-entry the well for surveillance or PLT. Total cost for the workover is approximately $80,000 including rig days, perforation and testing services. Since the water injection was driven by the pressure difference between the reservoirs, dumpflood injection is expected to start immediately after the workover was completed. IV. RESULT & ANALYSIS Surrounding wells performance was closely monitored since the first day of injection. However, due to limitation of downhole monitoring tool installed at producer wells, pressure response was monitored from fluid level increase by using sonolog measurement. To measure the actual cross flow rate, the spinner survey was run on well DF1.The objective was to confirm there is injection intake as well as quantify the rate of injection. First spinner survey was conducted a month after first injection. Cross flow was confirmed from Bravo to Alpha Sand with estimate injection rate around 620 BWIPD. No casing leak or theft zone observed from the spinner log, which gave the idea that 100% water from Bravo Sand goes to the right target zone, Alpha Sand. A month afterward, second survey was conducted with almost similar result. Cross flow rate was slightly increased to 680 BWIPD.


The first two spinner survey results showed good consistency of injection rate which indicated true capability of both sand. Figure 5 shows significant pressure response from fluid level trend at adjacent producer wells after first injection in place. At well P1, significant pressure response happened aggressively considering the close proximity of well P1 to well DF1 which approximately 92m. Positive pressure response also observed few months later at more updip oil producer, well P2 which is located 280m south of well DF1. However, the fluid level data point in P2 was not as many as data point at well P1 since this well was identified gassy which leads to ambiguous sonolog reading (foam). To gain the momentum of flooding response, pump upsizing program was executed in surrounding producer wells. The first upsize program was executed on well P1 by increasing the pump size from P6 (pump capacity 600 BFPD) to P16 (pump capacity 1600 BFPD). This upsize job was a major success with 1st test oil gain 160 bopd. Figure 6 shows sustained oil production is observed for the next 6 months with almost no production decline. Fluid level trend post upsizing even indicated an upside potential to increase the fluid rate even more to optimize the production. The next upsize program was executed in well P2 few months later as shown in Figure 7. Even though the incremental production was not as significant as the first one, the flood response has proven to arrest the production decline resulting sustained oil production in over the last few months. V. DISCUSSION The pilot project of natural dumpflood in Oleander field has been proven to be an effective pressure maintenance method and has successfully delivered significant production gain. The flooding response was clearly observed at surrounding producer wells in the matter of weeks, which affirmed that both target and source zone have decent reservoir properties and good lateral connectivity as predicted. Actual pilot production rates were found consistent with production rates predicted earlier by computer simulation. However, the numbers are not exactly matched, since the

181

actual result was above the expectation. It is quite reasonable because MBAL software did not capture the heterogeneity of the reservoir and no consideration was made on upsizing as part of production acceleration. Better yet, the actual reservoir parameter was better than the inputted parameter on MBAL simulation. Parallel to that finding, cross flow from Bravo to Alpha Sand at well DF1 was also confirmed by spinner survey measuring fluid rate approximately at 700 BWIPD from two logging runs. The number was adequately consistent with mid case estimation (P50) from previous equation. Static Bottom Hole Pressure (SBHP) surveillance will be deployed at one of producer wells in Alpha Sand. The objective was to confirm the natural dumpflood response in a form of pressure increase. However, the pressure increase is forecasted to be insignificant assuming the injection rate still stable at 700 BWIPD while the withdrawal approximately 3500 BFPD, therefore the voidage replacement ratio for this reservoir is still 20%. This voidage replacement ratio indicates that more injectors are needed in the future for field-scale water flood to deliver more reserves into production. The proposed plan forward is to add more dumpflood wells at the eastern part as well as the southern part of Oleander field to form a peripheral injection pattern to cover the whole field. However, by estimate, significant additional cost will be required to convert these wells into injection wells (CTI), considering the need for deepening prior the execution of CTI. Other considerable alternative is using pumpassisted dumpflood, which will provide swift increase in injection rate to improve overall voidage replacement ratio. Overall, the Natural Dumpflood pilot execution in Oleander field has yielded positive results. The effort has unlocked the opportunity for oil recovery enhancement as indicated by a significant production increase from well P1 as well as the decrease in the oil decline rate in well P2. As shown in Fig. 8, total additional reserve from this effort alone is approximately 84 MBO until end of concession and 100 MBO if constrained by economic limit. Economic analysis using actual production data and actual workover cost show positive economic metrics of NPV M$ 326 with DPI 5.27. Those numbers

182


illustrated how profitable and cost effective VIII. REFERENCES this effort for implementation. With minimal investment and short initiation times, this pilot Ahmed, Tarek, McKinney, Paul D., 2005. Advance Reservoir Engineering. Elsevier, Inc., Oxford. was economically viable and has the potential to be implemented in other fields. Other potential Amyx, J.W., Bass, D.M., Whiting, R.L., 1988. Petroleum Reservoir Engineering: Physical applications include using a dumpflood to pilot a Properties. McGraw-Hill Book Company, Inc., larger scale waterflood in order to reduce risk of New York. large investment in a low oil price environment. VI. SUMMARY 1. Pilot project of natural dumpflood in Alpha Sand, Oleander has proven to be profitable pressure maintenance effort in a low oil price environment. It is a cost effective project with quick setup time, yet able to provide high production impact. From the pilot result alone, 100 MBO additional reserve was yielded, which is equivalent to 1.5% addition in RF. Economic calculation shows the project yields approximately M$ 326 with DPI 5.27 2. Good surveillance data - particularly pressure, hold an important role to determine Natural Dump-Flood strategy. 3. Pressure contrast is the main parameter that determines the effectiveness of injection rate. Other parameters that should be considered during candidate selection are reservoir properties, remaining reserve, and connectivity. Distance parameter will affect differently depending on target reservoir position, if target reservoir located beneath the source zone, longer distance will give benefit by creating additional hydrostatic pressure to inject the fluid. On contrary, if the target located above, shorter distance will be preferred in order to minimize pressure loss. 4. Increasing the off take rate by pump upsizing is recommended once pressure response is observed at producer well in order to gain the momentum of the flooding. VII. ACKNOWLEDGEMENTS The authors acknowledge Reybi Waren for his contribution during project assessments, as well as Paulus Suryono Adisoemarta and Prapta Maulana for the content review.

C.A. Davies: “The Theory and Practice of Monitoring and Controlling Dumpfloods” Paper SPE3733 presented at European Spring Meeting, Amsterdam, The Netherlands, May 16-18, 1972 Craft, B.C., Hawkins, M., 1991. Applied Petroleum Reservoir Engineering. Prentice Hall PTR, New Jersey. Dake, L.P., 1983. Fundamentals of Reservoir Engineering (1st Edition). Elsevier, Inc., Oxford. J. Rawding: Application of Intelligent Well Completion for Controlled Dumpflood in West Kuwait” Paper SPE-112243 presented at the SPE Intelligent Energy Conference and Exhibition held in Amsterdam, The Netherlands, 25-27 February, 2008 R. Helaly, A. Bekheit, M. Farahaty, M. Tawfik, Agiba Pet. Co.: “Overcoming the Typical Operational Problems & Cost of Water Injection Using Dumpflooding”, Paper, SPE 164661, presented at the North Africa Technical Conference & Exhibition held in Cairo, Egypt, 15-17 April 2013 R. Quttanair and E. Al-Maraghi, Kuwait Oil Co. Umm Gudair Production Plateau Extension, “The Applicability of Fullfield Dumpflood Injection to Maintain Reservoir Pressure and Extend Production Plateau”, Paper, SPE 97624, presented at the SPE International Conference in Asia Pacific held in Kuala Lumpur, Malaysia, 5-6 December 2005. W. Shizawi, H. Subhi. A. Rashidi, A. Dey, F. Salmi, M. Aisary, Petroleum Development Oman: “Enhancement of Oil Recovery through “Dumpflood” Water Injection Concept in Satellite Field”, Paper, SPE 142361, presented at the SPE Middle East Oil and Gas Show and Conference held in Manama, Bahrain, 25-28 September 2011. Yao, C.Y., Hill, N.C., McVay, D.A.: “Economic PilotFloods of Carbonate Reservoirs Using a PumpAided Reverse Dumpflood Technique” paper SPE 52179 presented at the 1999 SPE MidContinent Operations Symposium, Oklahoma City (March 1999)


183

APPENDIX

Figure 1. Historical reservoir pressure of productive zones.

Figure 2. Simulated production forecast.

Figure 3. Simulated recovery factors to various injection rate scenarios.

Figure 5. Fluid level increase at adjacent producer wells.

Figure 4. Natural Dumpflood (NDF) well completion.

184


Figure 6. Well P1 production performance.

Figure 7. Well P2 production performance.

Figure 8. Incremental production & additional reserve from NDF project.

Table 1. Summary of Alpha Sand Properties.

The Effect of Rock Mineral and Compositions on Surfactant Injection at Tempino Reservoir Sandstone: A Laboratory Study Pengaruh Mineralogi dan Komposisi Batuan Terhadap Injeksi Surfaktan Di Lapangan Tempino Reservoir Batupasir: Studi Laboratorium Taufan Marheandrajana1 dan Kharisma Idea2 [email protected]; [email protected] 1Petroleum Engineering, Institute of Technology Bandung, Bandung 40132, Indonesia; 2Petroleum Engineering, UPN “Veteran” Yogyakarta, D.I. Yogyakarta 55283, Indonesia Abstract The purpose of this study is to investigate the effect of mineral and rock grains composition onthe anionic surfactant injection. Three surfactants were used. Two are anionic Alkyl Carboxylate added bynon-ionic cosurfactant and subtle amount of polymer (namely AN2NS and AN3NS). They differ only on the content of nonionic co surfactant.The other was non-ionic surfactant Alkyl Ester Polyethylene Glycol (NSS-26C).Surfactant injection was performed oncores of Berea and Tempino Field. On a laboratory scale, the surfactants were tested for aqueous stability, phase behavior, Critical Micelle Concentration (CMC), and thermal stability. Mineral contents and grain composition of rocks was done by using X-ray Diffraction (XRD), Petrographic, Scanning Electron Microscope (SEM) and Energy Dispersive X-ray Spectroscopy (EDS). Observation in this study suggested that the present of calcite and dolomite (with Ca and Mg positive charges) and clay as cement that fill the pores react with anionic surfactant (negative head charged forms deposit inside pores that decrease porosity of core at the time of injection. The interlocking porosity and secondary porosity with carbonates and clay cement cause trap residual oil difficult to be displaced by surfactant injection. On the other hand, the presence granule with carbonate matrix arranged in layers assist injection when its bedding direction is parallel to the flow direction. Keywords: Surfactant Injection, Tempino Oil Field, Anionic Surfactant, Non-ionic Surfactant.

Abstrak Tujuan dilakukan penelitan ini adalah untuk mengetahui pengaruh mineral dan susunan butir batuan terhadap injeksi surfaktan. Tiga surfaktan yang digunakan adalah dua surfaktan anionik yaitu AN2NS, AN3NS dan satu surfaktan non-ionik NSS-26C. Surfactant anionik yang digunakan adalah jenis Alkyl Carboxylate dan surfaktan non-ionik yang digunakan adalah Alkyl Ester Polyethylene Glycol. Injeksi surfaktan dilakukan pada core Berea dan core Tempino. Pada skala laboratorium, surfaktant di atas telah diuji aqueous stability, phase behavior, Critical Micelle Concentration (CMC) dan Thermal Stability. Uji kandungan mineralogi dan susunan butir batuan dilakukan dilakukan dengan uji X-ray Diffraction (XRD), Petrografi, Scanning Electron Microscope (SEM) dan Energy Dispersive X-ray Spectroscopy (EDS). Hasil studi ini menunjukkan bahwa keberadaan mineral batuan seperti calsite dan dolomite (dengan kandungan Ca dan Mg)sebagai semen dan clay yang mengisi pori batuan akan bereaksi dengan sufaktan anionik sehingga menyebabkan endapan yang dapat menghalangi aliran, dan dapat menyebabkan affinitas surfaktan pada permukaan clay. Susunan butir batuan dengan montmorillonite dan semen calsite menyebabkan adanya interlocking porosity sehingga fluida tidak bisa menembus pori batuan dan sisa minyak yang terjebak sangat sulit untuk dimobilisasi oleh injeksi surfaktan.. Susunan butir batuan yang tersisip karbonat tersusun secara berlapislapis membantu injeksi surfaktan karena arah perlapisasan searah dengan aliran injeksi. Kata kunci: Injeksi Surfaktan, Lapangan Tempino, Surfactan Anionik, Surfaktan Non-ionik.

185

186 I. INTRODUCTION


end of pipette test was flame sealed and stored in an oven at temperature of 68oC (reservoir temperature of Tempino Field) for 15 minutes. Then, the pipette was shaken for 5 minutes and was put back in the oven. Observation was made for 24 hours, 48 hours, 7 days and 14 days to record form of microemulsion. It was to determine the types of surfactant system, either it was a type II (+), type II (-) or type III, in which the boundary areas of oil and water will form emulsion (Salter, S.J., 1986). Micro-emulsion is hardly formed when divalent ions is present in the injection water and formation water (Sugihardjo, et al., 2001). Phase behaviour of the three surfactant is given in Figure 2. Interfacial Tension (IFT) Test. Was conducted using spinning drop tensiometer at temperature of 68oC. The measurement was run for maximun 30 minutes at 6000 rpm. Interfacial tension of oil-surfactant solution was recorded. This measurement was repeated for various concentration of surfactant to determine Critical Micelle Concentration (CMC), as is shown at Figure 3. Filtration Test. It was performed to determine the possibility of plugging of surfactant injection. Filtration apparatus was equipped with membrane 0.45 µm. The filtration apparatus was filled in by surfactant solution as much as 550660 ml and it was properly closed. Then nitrogen gas stream was injected at 20 psig with a constant flow rate. Filtrate was collected at measuring cup and time was recorded every 20 ml of filtrate. This was continued until the filtration reached 500 ml. At the end of the test, membrane was check for the presence of sediment and filtration ratio was calculated using Equation (1).

Tempino field is part of South Sumatra basin with Air Benakat formations and sandstone reservoir. In this field, water injection has been performed since 1996 and up to date the recovery factor is about 35% of Original Oil In Place (OOIP). The remaining reserves are still high, bring the idea to do the research of surfactant injection potential to improve oil recovery. In particular, this study focus on investigating the effect of certain minerals, such as calcite and montmorillonite that are present in reservoir rocks, on the performance of surfactant injection. The presence of inorganic ion (such as Na+, Ca2+, and Mg2+) introduced during the dissolution of these minerals and the interaction with the surfactant can lead to precipitation and surfactant depletion and possibly even to reservoir plugging (Somasundaran et al, 1984). Grigg et al (2005) reported that five minerals which were responsible for surfactant adsorption, and they are montmorillonite, dolomite, kaolinite, silica and calcite. Three surfactants were used and they have passed preliminary testings such as aqueous stability, phase behaviour, interfacial tension, thermal stability and filtrations tests. The mineral contents and grain composition of rocks were determined using combination of X-Ray Diffraction (XRD), Scanning Electron Microscope (SEM) and Energy Dispersive X-ray Spectroscopy (EDS). Two type of rock samples were utilized; Berea cores and Tempino Cores. Each surfactant was injected on both cores and the results were analyzed and examined for the correlations with mineral content and grain compositions of rocks. Filtration Ratio = II. METHODOLOGY

......................... (1)

In this equation, t60, t80, t180, and t200 are time at cumulative volume of filtrate reaches 60 2.1 Preliminary Surfactant Tests ml, 80 ml, 180 ml and 200 ml, respectively. Thermal Stability. Surfactant solution Aqueous Stability Test. Surfactant was at CMC concentration was placed in the oven put in brine with concentration of 2% w/w and at reservoir temperature for three month. The observation was made for clear colour of solution, interfacial tension was measured every week no precipitation or solid deposition (Figure 1). (Figure 4). Phase Behaviors Test. This was conducted Detailed tests on the three surfactants by mixing 2% surfactant in brine and crude oil used in this study can be found in the study by with1: 1 ratio in a 5 ml pipette test. The upper Marhaendrajana et al (2013).

The Effect of Rock Mineral and Compositions on Surfactant Injection at Tempino Reservoir Sandstone: A Laboratory Study (Taufan Marheandrajana dan Kharisma Idea)

2.2 Coreflood Procedure

....................................... (4)

Equipment was checked to determine no leakage of nitrogen that is injected into core holder to provide net overburden pressure. It was also performed cleaning of core holder, cell fluid injection, inlet and outlet tubing core holder. Then it was to make sure all Coreflood equipment can run normally and it does not leak. Preparation of injection fluid field Tempino was done by filtering the brine to the size of the membrane was 0.45 µm. Density and viscosity of brine were measured at room and reservoir temperatures. Oil was filtered through 3 micron filter paper. Oil viscosity and density were measured at reservoir temperature. Cores were cut into diameter of 1 inch and length of 1.5 inch. Dry core was weight. Also, porosity and permeability of these cores were measured. Core was first saturated by brine.Then it was placed into the cell that wasconnected with a vacuum pump for 3 hours to remove air possibly still inside the core. Brine was entered into the cell to immerse core and connects the cell to the vessel containing brine. It was checked for no leaks in the connections. This was continued for 24 hours. Core was then removed from the cell and then weighed. Pore volume was computed using Equation (2). Vp =

187

... (2)

Oil saturation wasdone by injecting oil into brine saturated core at reservoir temperature to displace brine. Brine was collected at the measuring tube and the volume was recorded. It continued until no more brine was produced. Initial oil volume was calculated by Equation (3). ................................................. (3)

2.3 Minerals Quantification The quantification of minerals was performed using the following methods. First was X-Ray Diffraction (XRD), Petrographic analysis with a thin section at 0.01 ml using magnification of 5x, 10x, 15x and 20x, then Scanning Electron Microscope (SEM) and Energy Dispersive X-ray Spectroscopy (EDS) were conducted to look at the mineral of the core surface and to identify the type of atom of the mineral (Nathan, 2012). III. ANALYSIS 3.1 Properties of brine and oil from Tempino field The brine salinity of Tempino Field is 8110 ppm. As seen at Table 1, the brine cantains divalent ion Ca2+ and Mg2+ that may interact with the anion surfactant and may cause precipitation. At Table 2, the oil is composed of 71.6% saturated, 25.5% aromatics, 2.1 resins and 0.8 asphaltenes. Oil viscosity is 0.9 cp and oil gravity is 43.4 API. The Equivalent Alkane Carbon Number of oil is 8.29. EACN was used as consideration for designing chain number of hydrophobic tail of surfactant to form strong interaction with the oil.The optimum condition, however, is whenthe hydrophobic interaction withthe oil is as strong as the hydrophilic interaction withwater.The length of hydrophobic affect the rate of adsorption of surfactant. Adsorption will increase with the longer hydrophobic chain due to increased hydrophobic surfactants tend to push from the aqueous phase to the solid-liquid surface (Scamhorn, 1982).

Total Acid Number (TAN) is 1.23 At flowrate 0.3 cc/min, brine was injected mg KOH/g. The more acid number the more into core until no more oil was produced or preferable of using alkali to produce in-situ volume of injected brine reached 1.2 PV (pore soap. volume). It was then followed by injecting surfactant slug for 0.5 PV then by brine injection 3.2 Minerals of Berea and Tempino Cores for 4.5 PV. During the coreflooding process, From Table 3 and Table 4, it can be oil produced was collected and its volume was recorded. Recovery Factor (RF) was computed seen that the mineral composition of Berea and Tempino cores consist of similar mineral types using quation (4).

188


such as Quartz, Montmorillonite, Albite, Calcian, 3.4.1 Surfactant AN2NS respectively. The contrast between the two is that Tempino core has less quartz and more calcian. Cores with initial oil and water were 2+ The calcian which contain Ca may greatly injected by water as much as 1.2 PV (pore volume). affect the peformance of surfactant injection. It was continued by injecting surfactant solution with 2% concentration (plus 0.03% polymer) for 3.3 Testing and Analysis of Surfactants 0.5 PV followed by water injection for 4.5 PV. The addition of polymer in chemical formulation The surfactant used in this study is was not only used to control the water/oil mobility an anionic surfactant; AN2NS, AN3NS, and ratio but alsa affect the surfactant adsorption in non-ionic surfactant; NSS-26C. Anionic different ways (Wang et al, 2015). and nonionic were prefered than cationic The oil and water used ini coreflood surfactants, as sandstone (contain silica) tend process were formation (Tempino) oil and water. to negatively charged (Wadudi et al., 2016). Two cores were used. One is Berea core and one The three surfactant showed ability to dissolve is Tempino reservoir cores (code: TPN#37). in water very well and no precipitation was Descriptive and quantitative analysis of observed (Figure 1). Filtration ratio of the three cores used in this coreflood are as follow. surfactants is below the maximum permitted Refer to descriptive guidance by Pettijohn number of 1.2 (Table 5). It suggested that no (1987), Berea core is Orthoquartzite. Petrographic plugging was expected duting injection. Figure analysis of thin section indicated Berea core is 2 depicts that phase behaviour of AN2NS and sedimentary rock, sandstone, texture clastic, AN3NS indicate Type III showing middle disaggregated medium-bad, pack open (long phase of microemulsion. Meanwhile, NSS-26C contact, point contact), granules 55% consists of phase behaviour indicate Type II(+) showing quartz (C2) and K-Feldspar (D3), shaped angled. upper phase microemulsion (water in oil). The Matrix (B5) is silica and K-Feldspar (5%) phase behaviour is consistent with the IFT present binding granules, colorless. Cement (F2) measurement results shown is Figure 3. The is silica (5%) colorless, filling the space grains, IFT of AN2NS and AN3NS (middle phase subhedral-anhedral crystal form. Porosity (30%) microemulsion) are lower than IFT of NSS- intergranular. In Berea found indications of 26C (upper phase microemulsio) at individual hydrocarbons fill the spaces between the grains. Critical Micelle Concentration (CMC). Characterized with black on PPL and XPL seen in Consistency of thermal stability of D5, I7, I9 and K8 (Figure 5).The results of SEM anionic surfactant is shown by Figure 4. In and EDS for Berea core are shown on Figure 6 contrast, non-ionic surfactant NSS-26C is lack and Table 8. Descriptive and quantitative analysis of stability when it was exposed to reservoir above were done on Berea core L#39. temperature for more than one week. It is TPN #37 core is a sandstone graywacke. because molecular structure of Alky Esther On analysis petrographic TPN #37 is a thin section (NSS-26C) the bond between Carbon (C) of sedimentary rock, sandstone, texture clastic, and Oxygen is unstable at high temperature, disaggregated medium, pack open (long contact, and broken apart into R-CO+ and R-O- which point contact), granules 60% is composed of 55% are unstable. In water they will form Alky quartz (F1), 2% plagioclase (V18), 3% angled carboxylate (R-COOH) and alcohol (R-OH). On half-rounded shape. Matrix (D3) in the form of the contrary the Alkyl Carboxylate (R-COOH) brown clay and colorless quartz (20%), cement is more stable at high temperature. (15%) of silica is colorless and carbonate (15%), porosity (5%) intergranular (Figure 7 and 8). 3.4 Coreflood Experiments Result of SEM and EDS for TPN#37 are shown in Figure 9 and Table 9. Three Berea Cores and four Tempino Berea core has better quality with cores were used in the experiment. Properties and higher porosity, less cement and less clay dimension were measured as shown in Tables 6 contents. In Berea core, cement consists of and 7. silica, while in Tempino core cement consist of


silica and carbonate minerals. The present of Na+, Ca+, Mg2+, and Al3+ in clay and cements were discussed on their effect on the surfactant injection performance. Initial water injection on Berea core produced more oil recovery than on Tempino TPN#37 core. This was consistent given Berea core is more homogen, higher porosity and less clay and cement. The oil recovery during initial water injection was 44% on Berea core and 17% on TPN#37 as shown in Figure 10. Surfactant injection afterward on TPN#37 was preceeded by injecting alkaline to preconditioning the rock surface to minimize surfactant adsorption due to present of anhydrite (calcite) which will cause solid precipitation when injecting anionic surfactant (Sheng, 2011). After surfactant injection, the oil recovery increase from 44% to 74% on Berea core and increase from 17% to 32% on TPN#37 core. Thus, the incremental oil recovery after introducing surfactant injection was 30% on Berea core and 15% on TPN#37 (Figure 11). We investigated the correlation of the content of Na, Mg, Ca and Al with the incremental oil recovery by surfactant injection. Mg2+, Ca2+ compose dolomite and carbonates, and Na+, Mg2+, Ca2+ are hold on clay mineral, such as montmorillonite. As seen in Table 9, increase of Na+, Mg2+, and Ca2+ affected performance of surfactant (Alkyl Carboxylate) indicated by lower incremental oil recovery. The divalent ion reacted with COOform pricipitation in the pores which harm the oil displacement. The present Na+, Mg2+ and Ca2+ in clay minerals may exchange with H+ from dissosiated surfactant in brine solution. This may cause adsorption of surfactant in clay surface. 3.4.2 AN3NS In this case, two cores, Berea and TPN#56 were used in the coreflooding experiments. Surfactant solution with 1% concentration (CMC) was injected after initially injecting water. Polymer of 0.03% was added in the solution. TPN #56 core is graywacke. Petrographic analysis of TPN #56 core is a thin section of sedimentary rock, sandstone, clastic texture, being disaggregated, open container (long contact), granules 65% (D1) consists of quartz, angled half-rounded shape. Matrix form of

189

brown clay and quartz (B4) present binding details (15%). Cement 15% (I8) consists of silica colorless (10%) and carbonate (5%) and porosity (5%) intergranular (Figure 12 to 14). SEM of TPN#56 is shown in Figure 15. Grain arrangement of TPN#56 is in form of layering in the direction of flow (Figure 12). This may explain the oil recovery during initial water injection reached 74% and higher than oil recovery on Berea core which is only 37%. During injection of surfactant on TPN#56, differential pressure increases from 3 psi to as much as 12.5 psi. This may be an indication of pore blockage that was caused by solid precipitation. The incremental oil recovery from surfactant injection on TPN#56 was 9% much lower than Berea core was 20% (Figure 16). The oil recovery from this core was assisted by granule layers are parallel to the flow direction. Petrographic results showed the existence of large and small foraminifer fossils, strongly indicated by the presence of. Glukonit in the fossil record. Carbonate sediments were dominantly visible white and arranged in layers. The existence of carbonates and clays were unfavourable for anionic surfactant. On the contrary, EDS data in Table 10 does not show any Ca content but it does show the present of Mg which is a component of dolomite as diagenesis form of carbonate. 3.4.3 NSS-26C Figure 3 shows that the surfactant solution (NSS-26C) has an IFT value of 5x10-3 mN/m, which is in compliance for surfactant injection. Surfactant concentration was 2% and 0.03% of polymer was added in the solution. Initial water injection on TPN#46 was 71% and it was higher than on Berea, which was 35% (Fig.18). The incremental recovery by surfactant injection, however, was higher on Berea core (24%) and was no incremental recovery on TPN#46 (Figure 19). Core TPN #46 is graywacke. Petrographic analysis of core TPN # 46 is a thin section of sedimentary rock, sandstone, clastic texture, medium disaggregated, open container (long contact), granules 65% consists of quartz (D1), rounded shape angled responsibility. Matrix (15%) consists of brown clay and colorless quartz (15%). Cement 15% (K6) consists of silica (10%) and carbonate (5%). Porosity (5%) is intergranular (Figure 20).

190


Carbonate cement filling the space between grains that leads to reduced porosity and cover the pores between grains that cannot remove the oil on the core (Figure 21). Rock grains are arranged lengthwise so that the pores between the rock were formed. Interlocking rock porosity (C3) resulting from clay and carbonate cement that fills the pores between grains. Secondary porosity was observed in the form of a cavity in the shell. This pores structure, grains arrangement, and cement filling cause trapped oil in the matrix and in the cavity of fossil shells, as they are covered by mineral clay and carbonate cement. This caused the injection of surfactant did not successfully remove the oil that was trapped in the core TPN #46. EDS in Table 11 derived from SEM (Figure 22) detected Mg as an indication of dolomite. IV. CONCLUSIONS 1. The presence of carbonates matrix or cement with Ca and Mg content cause solid precipitation during injection anionin surfactant Alkyl Carboxylate. Ca2+ and Mg2+ tend to react with R-COO-. 2. Clay with surface cation Na+, Ca2+, Mg2+ promote ion exchange with surfactant Alkyl Carboxylate R-COOH, which is dissosiated into R-COO- and H+ in water solution. This likely cause affinity of the surfactant on clay surface which result in adsorption of surfactant. 3. Grain arrangement with interlocking porosity, secondary porosity and allignment of carbonates and clay cement makes trap residual oil after water injection is difficult to displaced by surfactant injection. 4. The composition of the granules that are layered can assist water/surfactant injection when the bedding direction is parallel to the flow direction. V. ACKNOWLEDGEMENT We acknowledge support from ITB and PT Pertamina EP for the completion of this study.

VI. SYMBOLS W3 W2 ρoil ρbrine t200 t100 t80 t60

= Weight of oil saturated = Weight of brine saturated = Oil Density = Brine Density = Time to accommodate 200 ml fluid = Time to accommodate 100 ml fluid = Time to accommodate 80 ml fluid = Time to accommodate 60 ml fluid

VII. REFERENCES Grigg, et al., 2005. Sorption of Surfactant Used in CO2 Flooding Onto Five Minerals and Three Porous Media. SPE 93100. Marhaendrajana, et al., 2013. Studi Pengembangan Injeksi Surfaktan di Lapangan Kenali Asam Di Tempino. Laporan, Institut Teknologi Bandung. Nathan, D. et al, 2012, Reservoir Characterization of Lower Pennsylvanian Sandstones for the Application of ASP Flood Technology in Lawrence Field, Illinois, AAPG, Long Beach, California. Pettijohn, F. J., 1957, Sedimentary Rocks, 2nd Edition, Harper & Row, New York, p. 229-249. Salter, S. J. 1986., “Criteria for Surfactant Selection in Micellar Flooding”, SPE paper 14106, SPE. Scamhorn, J.F., et al., 1982. Adsorption of Surfactants on Mineral Oxide Surfaces from Aqueous Solution. I. Isomerically Pure Anionic Surfactants; Journal of Colloid Interface Science, 85, 463-478. Sheng JJ., 2011, Modern Chemical Enhanced Oil Recovery: Theory and Practice, Gulf Proffesional Publishing, New York. Somasundaran, et al., 1984. The Role of Surfactant Precipitation and Redissolution in the Adsorption of Sulfonate on Minerals. SPE Journal, p 233-239. Sugihardjo., et al., 2001. Kelakuan Fasa Campuran Antara “Reservoar-Injeksi Surfaktan” Untuk Implementasi Enhanced Water Flooding. Prosiding Simposium Nasional IATMI. Wadudi, et al., 2016. Laboratory Study: Analysis of The Effect of Carbonate In Carbonate-Cemented Sandstone To Oil Recovery With Spontaneous Imbibition Test Using Surfactant. Proceeding Indonesian Petroleum Association. Wang, et al., 2015. Surfactant Adsorption in Surfactant-Polymer Flooding for Carbonate Reservoirs.


191

APPENDIX A FIGURE

Figure 1. Aqueous Stability of AN2NS, AN3NS and NSS26C.

Figure 2. Phase behavior of AN2NS, AN3NS and NSS26C.

Figure 3. CMC curve of AN2NS, AN3NS and NSS-26.

Figure 4. Thermal stability of AN2NS, AN3NS and NSS26C.

Figure 5. Thin Section result of Berea L #39.

Figure 6. SEM result of Berea L #39.

192


Figure 8. Thin Section result of TPN #37 (oil indication).

Figure 7. Thin Section result of TPN #37.

Figure 9. SEM Result of TPN #37: Inlet, Mid, and Outlet Sections.

Figure 10. Surfactant Injection result of AN2NS.

Figure 11. Incremental Recovey of AN2NS.

Figure 12. Thin section result of TPN #56 (Magnifications 1 mm).

Figure 13. Thin section result of TPN #56 (Magnifications 0.5 mm).

Figure 15. SEM result of TPN #56.

Figure 14. Thin section result of TPN #56 (Magnifications 0.125 mm).


Figure 16. Surfactant injection result of AN3NS.

Figure 17. Incremental recovery of AN3NS.

Figure 18. Surfactant injection result NSS-26.

Figure 19. Incremental recovery of NSS-26C.

193

Figure 20. Thin Section result of TPN #46 (magnifications 0,125 mm).

Figure 21. Fossil foraminifera of TPN #46 (magnifications 0,125 mm). Figure 22. SEM result of TPN #46.

194


APPENDIX B TABLE Table 1.Content of metals and organic compounds in the Tempino brine.

Table 2. SARA test results and other properties of Tempino oil.

Table 3. Mineral Content of Berea.


Table 4. Mineral Content of Tempino Layer B/600.

Table 5. Filtration Test Results surfactant with Tempino brine.

Table 6. Berea Core Properties.

Table 7. Tempino Core Properties.

Table 8. EDS Test Result of Berea Core L # 39.

195

196


Table 9. EDS Test Result of Berea Core and TPN#37 Cores.

Table 10. EDS Test Result of Berea and TPN#56 Cores.

Table 11. EDS Test Result of Berea and TPN#46 Cores

Techno-Economic Evaluation of Carbon Capture Storage Ready for Coal-Based Power Generation in Indonesia Evaluasi Tekno-Ekonomi untuk Pembangkit Listrik Berbasis Batubara di Indonesia Usman1, Sugihardjo2, Danang Sismartono3, Aziz M. Lubad4, Oki Hedriana5 dan Arief Sugiyanto6 [email protected] (1)(2)(3)(4)(5)R&D Center for Oil and Gas Technology “LEMIGAS”, Jakarta, Indonesia; (6)Indonesian State-Owned Electricity Company, PT. PLN, Jakarta, Indonesia Abstract To meet the rapidly growing demand and to provide secure base load power supply, Indonesia’s power sector is seeing a growing share of coal in its generation mix. However, increased coal-based generation contributes to increased CO2 emissions. This study aims to define and evaluate the conditions under which coal-based generation could be deemed as carbon capture and storage ready. It considers the technical and economic implications of CO2 capture and storage for two candidate coal power plants in South Sumatera and West Java. A carbon capture storage of a couple of scenarios are evaluated for each power plant based on separation of 90%, 45% and 22.5% of CO2 from the power plant flue gas with an amine scrubbing process, supported by flue gas cleaning processes, and liquefaction of the captured CO2 for transportation to geological storage locations. The carbon capture storage operation would also run for 20 years, 15 years and 10 years, while the power plant design life is 25 years. The potential to sell captured CO2 for enhanced oil recovery in South Sumatera is also assessed. Results of this study will help Indonesia to identify a way to reduce CO2 emissions from the coal-based power sector in the long run and will contribute significantly to putting the country’s energy sector on a sustainable development path. Keywords: CCS-ready, coal power plant, CO2 capture, CO2 emissions, CO2 EOR.

Abstrak Untuk memenuhi pertumbuhan permintaan listrik yang cepat dan mengamankan pasokan beban dasar, maka porsi batubara sebagai bahan bakar pembangkit listrik akan ditingkatkan. Peningkatan pembangkit listrik berbasis batubara akan berdampak pada peningkatan emisi CO2. Studi ini bertujuan menentukan dan mengevaluasi pada kondisi mana pembangkit batubara siap jika diintegrasikan dengan teknologi penangkapan dan penyimpanan CO2 atau carbon capture storage ready. Studi kasus berdasarkan implikasi teknis dan ekonomi akibat penambahan peralatan penangkapan dan penyimpanan CO2 pada dua kandidat pembangkit listrik batu bara di Sumatera Selatan dan Jawa Barat. Evaluasi berbagai skenario carbon capture storage berdasarkan pemisahan 90%, 45% dan 22,5% CO2 dari gas buang pembangkit menggunakan proses amine scrubbing, proses pemisahan impuritis yang terkandung dalam gas buang, dan likuifaksi CO2 untuk transportasi ke lokasi penyimpanan pada formasi geologi. Skenario masa operasi teknologi carbon capture storage adalah 20 tahun, 15 tahun, dan 10 tahun. Usia pembangkit didesain 25 tahun. Dalam studi ini juga dievaluasi pemanfaatan CO2 yang ditangkap dari pembangkit untuk meningkatkan perolehan minyak tahap lanjut pada reservoar-reservoar minyak di Sumatera Selatan. Hasil studi ini akan membantu Indonesia dalam mengidentifikasi cara mengurangi emisi CO2 dari sektor listrik pembangkit batu bara dalam jangka panjang dan akan memberikan kontribusi signifikan bagi sektor energi di Indonesia agar berada pada jalur pembangunan yang berkelanjutan. Kata Kunci: CCS-ready, pembangkit listrik batubara, penangkapan CO2, emisi CO2, CO2 EOR.

I. INTRODUCTION

meet growth in electricity demand because of the relatively abundant domestic supply. Under Indonesia’s government encourages a sustainable energy scenario, coal power plants increased use of coal in the power sector to will dominate the additional capacity power plant 197

198


during 2015-2050, with a share of 66% [1]. Coal is regarded as a low cost fuel source in electricity generation but is generally more carbon intensive compared to diesel and fuel oil. Coal powers are major emitters of carbon dioxide (CO2), a greenhouse gas (GHG) which is a contributor to global warming. The rising use of coal power will contribute to an increase in the country’s emissions. Power generation is currently responsible for about 32% of energy-related GHG emissions and will increase by 49% by 2050 relative to a business-as-usual case. [1]. The biggest emitters are coal-based. In order to meet the country’s need for improved energy supply and security, while also constraining GHG emissions, future coal-based power plants may have to include decarbonisation technologies. The available technology is CO2 capture and storage (CCS). CCS technologies can dramatically reduce up to 90% of CO2 emissions from coal power plants [2]. For this reason, CCS is expected to play a large role in future GHG mitigation strategy that permits countries to continue using fossil fuels whilst achieving deep reductions in CO2 emissions [3, 4]. The CCS process involves three key components [5, 6]: (1) capturing, dehydration, and compression of CO2 from large stationary emissions sources; (2) transporting CO2 by tankers, pipeline, or ship to suitable storage sites; (3) injecting CO2 deep underground for secure storage. Figure 1 provides a simplified schematic of the integration all CCS elements. Although some initial applications of CCS have been made for enhanced oil and gas recovery and for natural gas processing, experience so far of the application of CCS for power generation is very limited. Challenges remain to minimize cost and efficiency penalties and to demonstrate safe, long-term storage of CO2. Government and industry have been working to resolve these challenges, but in the meantime new fossil-fuel power plants and industry plants continue to be designed built worldwide. Long-term operation of these new plants could result in a situation in which plants continue to emit large amounts of CO2 if mitigation through CCS is technically and economically infeasible due to equipment and site constraints. The desire to avoid these risks

has led to a concept known as CCS-Ready (CCSR), in which carbon-emission-intensive plants prepare for CCS during their design and planning phase [7].

Figure 1. A simplified schematic of integration of all CCS elements.

CCSR is as a planning tool to facilitate CO2 mitigation in the future when the necessary regulatory and economic drivers are in place. A CCSR policy would require or encourage carbonemissions-intensive plants to prepare for all CCS elements during the design and planning phases, so that the plants are more ready to retrofit CCS in the future. If such preparatory measures are taken now, they may lead to reduced costs and less economic disruption in the future [7]. The CCSR concept is relevant for Indonesia where large numbers of new fossil fuel based plants are expected to be constructed in the near term. A comprehensive study to assess the value chain of CCS in Indonesia was initiated in 2012 [8]. The study identifies priority technologies and sites for a CCS pilot project, reviews policy, technical, geological, regulatory, financial, and public acceptance issues. An actionable road map for a CCS pilot project in Indonesia that provides the basis for future demonstration and commercial‐ scale projects was also established. The study focused on South Sumatera which possesses several attributes that makes it well suited to CCS: abundant resources, many opportunities for storage and enhanced oil recovery (EOR), and an existing transport network linked to oil and gas activities. It has also many large stationary sources of CO2 from power generation and industrial activity that can be captured.

Techno-Economic Evaluation of Carbon Capture Storage Ready for Coal-Based Power Generation in Indonesia (Usman, Sugihardjo, Danang Sismartono, Aziz M. Lubad, Oki Hedriana dan Arief Sugiyanto)

The prospects for CCS facilities installed to coal-based power generation in Indonesia was further assessed [9]. The assessment addressed the conditions under which coal-based power generation could be deemed as CCS-Ready (CCSR). Technical and economic implications of CCSR implementation in the power sector based on current available technologies were evaluated. In addition, EOR as a potential costoffsetting mechanism for CCS projects in the power sector was examined. Findings from this study are presented in this paper. It should be of interest to a broad audience interested in reducing CO2 emissions to the atmosphere such as policymakers, government agencies, project developers, academicians, and civil society and environmental non-governmental organizations in order to enable them to assess the role of this technology in national energy strategies and its impact on local communities. II. METHODOLOGY

199

and economically feasible. The method of post combustion-capture which is the most developed technique employed in industry for capturing CO2 from the exhaust gases of fossil fuel combustion are described and assessed. Transport-readiness identifies a practical transport route with accessible rights-of-way between the power plant and the storage locations with its associated cost. Storage-readiness focuses on identifying the opportunity for geological storage of the large volume of captured CO2 for the project lifetime of the CCS scheme. A qualitative assessment of CO2 for EOR as a cost-offsetting mechanism for CCS projects in Indonesia is also established. III. OBTAINED RESULTS Two candidate coal power plant designs were selected for this study. The larger 2x1000MWe ultra-supercritical units in West Java will use a high-sulphur lignite coal from Kalimantan or Sumatera. The smaller 1x600MWe supercritical unit in South Sumatera located near a coal mine will use lower sulphur lignite. These two power plants are assumed to be commissioned in 2020 and 2022, respectively. Total annual CO2 emissions based on separation of 90%, 45% and 22.5% of CO2 from the flue gas are given in Figure 2. The estimated quantity of CO2 captured at a 90% CO2 capture rate would be 10.9 million tonnes CO2 per year (MtCO2/ year) for West Java power plant and 3.7 MtCO2/ year for South Sumatera power plant.

Coal-based power plants referenced in this study were selected based on the following set of criteria: the power plants targeted should be large units (>600 MW), space availability for subsequent CO2 capture and compression equipment installation, the choice of plants expected to begin operation in 2018 or later, should be representative of Indonesia’s generation mix, and availability of CO2 storage in the region. A couple of CCSR scenarios are evaluated for each selected power plant based on separation of 90%, 45% and 22.5% of CO2 from the power plant flue gas for transportation to geological storage locations. The CCS run operations are: no delay with 25 years of operation, 5-year delay with 20 years of operation, 10-year delay with 15 years of operation, and 15-year delay with 10 years of operation. The economic assessment reference case is based on CCS being built with no delay, for comparability with other technologies. Performance parameters were derived from Figure 2. CO2 emissions from the reference West Java and prefeasibility studies and expert views. Therefore, South Sumatera power plants based on separation of 90%, 45% and 22.5% scenarios. they should be viewed as indicative. CCSR involves capture-readiness, transport-readiness, and storage-readiness. Capture Ready Capture-ready status was established considering Being CO2 capture ready satisfies at least CO2 capture design, site area requirements, and additional equipment locations that are technically the following criteria [7]: sited such that transport

200


and storage of captured volumes are technically feasible, technically capable of being retrofitted for CO2 capture using one or more reasonable choices of technology at an acceptable economic cost, and adequate space allowance has been made for the future addition of CO2 capturerelated equipment. This section described the last two criteria, while the first criterion will be discussed in the next sections. Three major approaches have been developed for capturing CO2 from coal-based power generations: post-combustion capture, pre-combustion capture, and oxy-combustion process [6]. Post-combustion capture is the most developed technique employed in industry for capturing CO2 from the exhaust gases of fossil fuel combustion [6, 10, 11]. It can be retrofitted at a relatively low cost to existing power stations without radical changes on them compared to the other two approaches [10, 11]. CO2 from the flue gas is absorbed by a chemical solvent. After the absorption, the CO2-rich solvent is heated and regenerated before recycling back to the next absorption cycle, while CO2 released from the solvent can be separated, dried, and compressed for transportation. Monoethanolamine (MEA), a popular chemical solvent, is frequently used in many CO2 capture situations and is currently in commercial use [11, 12]. A low pressure (LP) steam turbo-generator would be required for amine solvent regeneration. Due to their proven record of usage in industrial processes, MEA-based post-combustion capture system was adopted in designing CO2 capture-ready for the both selected power plants. Before being processed in the CO2 capture system, acid gases such as NO2 and SO2 must be removed from the discharged flue gas as they affect the performance of the system by forming heat stable salts with MEA solvent. Environmental air quality legislation in Indonesia requires the discharge of NOx less than 750mg/Nm3 (365 ppm). NO2 concentrations of 20 ppm for MEA process are recommended [11]. Therefore, an additional process with about 95% NOx reduction would be needed. A Selective Catalytic Reduction (SCR) unit could achieve that level. To be capture-ready a power plant would require space to be allocated for retrofitting SCR in the hot gas path.

Concentration of SOx of below 750 mg/ Nm3 (263 ppm) in the discharged flue gas is required to comply with air quality regulation in Indonesia. The MEA process typically requires the feed gas to contain less than 10 ppm SO2. SOx removal is usually achieved in a Flue Gas Desulphurization (FGD) unit [11]. For a flue gas that is compliant with the air quality criterion, an additional FGD process with 96% SO2 reduction capability would be needed and placed in the host power plant flue gas prior to the CO2 capture system. The intention to use high-sulphur lignite coal for the West Java power plant would result in a flue gas of around 4825 mg/Nm3 of SO2. To make the feed gas compliant with the MEA scrubbing requirement, a two stage SO2 removal process was proposed. The flue gas would first be reduced to below the air quality of 263 ppm with seawater scrubbing at a coastal location. A further 96% reduction in SO2 is achieved in a highefficiency wet FGD unit. In the case of the South Sumatera power plant, seawater scrubbing is not possible. The use of a single wet FGD process would be practical if a lower sulphur content of around 0.28% can be used. It will result in a flue gas of around 750 mg/Nm3 of SO2 that is compliant with the air quality criterion. NOx and SOx removal configuration for both power plants is illustrated in Figure 3. CO2 that has been stripped from the amine solvent in the regenerator tower will be prepared in a CO2 conditioning system. In order to transport large amounts of CO2 efficiently and avoid unnecessary problems of vaporization, the CO2 must be liquefied and maintained in the liquid phase in the pipeline. The critical temperature and pressure of CO2 are 31oC and 74 bar. When the CO2 is at a higher level of its critical properties, it would be a supercritical fluid rather than a liquid. Therefore, to provide the pipeline pressure and maintaining it in liquid phase, CO2 is compressed at the power plant site with cooling and dehydration to 110 bar. The CO2 from the scrubber is saturated with water after being regenerated with steam in the stripper column. Excessive amounts of water would cause corrosion problems in the delivery pipe. For that reason, a water removal process must be included in the CO2 compression train. A CO2 conditioning configuration using compressors and dryers (C&D) is illustrated in Figure 4.


201

Transport Ready

Figure 3. NOx and SOx removal configuration.

Figure 4. CO2 conditioning configuration.

As described above, making the selected power plants CO2 capture-ready requires additional equipment comprising: SCR for NOx reduction, FGD to reduce SOx content of the flue gas, MEA for CO2 removal equipped with LP steam turbo-generator for amine solvent regeneration, and C&D for conditioning of CO2 in order to comply with the CO2 pipeline specifications. Figure 5 shows a simplified schematic of the additional equipment that would be required for capturing CO2 from coal-based power generation. The four major process areas need to be allocated space on the power plant site. Table 1 presents an estimate of the total additional land areas required. The West Java power plant would require approximately six hectares of additional land space for 90% CO2 capture system and its complementary facilities. The South Sumatera power plant needs about three hectares of additional space. Installation of the equipment would reduce the net electricity delivered to the transmission grid. For the case of 90% CO2 capture resulted in about a 27% and 31% reduction in net electricity output for the West Java and South Sumatera power plants, respectively. The main cause of electricity output reduction is the net loss due to LP steam use for CO2 capture. Figure 6 presents capital cost estimates for additional process equipment for all scenarios. The inset figure depicts estimated annual additional operating cost.

Being CO2 transport ready satisfies at least the following criteria [7]: potential transport methods are technically capable of transporting captured CO2 from the source(s) to geologic storage ready site(s) at an acceptable economic cost, transport routes are feasible, rights of way can be obtained, and any conflicting surface and subsurface land uses have been identified and/or resolved. CO2 can be transported at small scale as a liquid in high-pressure containers at low temperature by truck, rail, or ship. However, in a large volume, the use of pipelines is the only viable technology [13]. Shipping becomes more economical than piping for the transport of CO2 over a long distance (>1000 km) [4]. The use of pipelines is proposed in this study. Pipeline sizing has been designed with a large diameter, low velocity, and low pressure drop to avoid recompression stations.

Figure 5. The capture-ready facilities retrofit in a power plant. Table 1. Estimated Site Area Needs For CO2 Capture At Power Plants.

Transport of CO2 considered in this study involves the delivery of up to 10.9 million tonnes per year from the West Java power plant and up to around 3.7 million tonnes per year of CO2 from South Sumatera power plant. Transporting CO2 by pipeline must be maintained in the liquid state. The CO2 in a long distance pipeline will be

202


Figure 6. Estimated additional capital and operating costs for 90% CO2 capture.

and the identified storage sites of onshore natural gas fields in Northwest Java. Analysis presented in next section found that the 17 on-shore gas fields shown on Fig. 6 only have enough capacity to store 164 MtCO2. Therefore, about half of the CO2 storage capacity of the largest off-shore gas field has been included in the assessment of on-shore CO2 storage of the CO2 captured from West Java power plant. The locations of existing gas gathering pipelines are also shown on the figure. The routes of CO2 pipelines for this scenario were assumed to use these existing right of way pipeline corridors. The overall transmission pipeline would be 293 km long, initially at 34 inch diameter and reducing progressively to 14 inch diameter, with smaller pipes branching to the gas fields. In total, over 500 km of pipeline would be required in the transmission and distribution network for onshore gas field storage in West Java, as shown in Figure 8. Transmission relates to bulk pipelining of CO2 from the power plants to distribution hubs which are local to the CO2 storage locations. Distribution relates to the delivery of CO2 from the distribution hubs to the CO2 injection points.

at ambient temperature, which is typically 25 to 30oC in Indonesia. This temperature is close to the CO2 critical temperature of 31oC. Therefore, the pressure of CO2 in the pipeline should be maintained above the CO2 critical pressure of 74 bar to avoid problems of vaporization while delivering it, so a minimum pressure of 80 bar is applied as a pipeline design criterion. Since the liquid CO2 would be delivered to the injection site at a pressure in excess of 80 bar, that delivered pressure would generally provide adequate driving force for CO2 injection, so additional compression at the well site should not normally be required. The formation pressure at depth in the well might be greater than 80 bar due to the groundwater hydrostatic pressure. Normally, the input pressure plus the vertical pressure head of CO2 in the well would overcome that pressure. However, under high geothermal gradient of 50oC/km as is common in South Sumatera and West Java, the well head pressure of 100 bar is required to deliver CO2 to about 2000 meters depth. A secure geological formation for long-time CO2 storage is typically Figure 7. Transmision network of CO2 from West Java power plant to on-shore gas fields in Northwest Java. found at least 800 meters below the ground. The scenarios of transmission and distribution pipeline networks discussed here are: West Java CO2 storage in on-shore gas fields in West Java, South Sumatera CO2 storage in gas fields, and South Sumatera CO2 storage in oil fields via EOR. The implementation of 90% CO2 capture at the West Java power plant would require capacity to store 10.9 MtCO2/year. If CCS is to be implemented five years after commissioning the power plant, then it would operate for the next 20 Figure 8. Distribution network of CO to injection points 2 years of the initial 25 years of power plant design in Northwest Java. lifetime. Accordingly, identified storage for up to The implementation of 90% CO2 capture 218 MtCO2 is essential to meet the storage-ready criterion for the cases evaluated. Figure 7 shows at the South Sumatra power plant would require the relative locations of West Java power plant capacity to store 3.7 MtCO2/year. If CCS were to


be implemented five years after commissioning the power plant, then it would operate for the next 20 years of the initial 25 years of power plant design lifetime. Accordingly, identified storage for 74 MtCO2 would be required to meet the CCS-ready storage criterion. Six depleted gas onshore natural gas fields have been identified to store the volume. Figure 9 shows a scheme for the transport of CO2 by pipeline to these eight storage locations. The total pipeline length is 92 km and the average diameter is 13.5 inches. An economically preferred storage location would be in depleted oil fields in the South Sumatra basin, with the possibility of revenue from sales of CO2 for EOR. The actual contribution of CO2 from the power plant to specific EOR locations would depend on timing and other factors. However, for the purpose of assessing transport costs, eight oil fields in the southeast quadrant of the South Sumatra basin have been identified as having the overall EOR demand to match more than half of the supply from the South Sumatra power plant. Distribution pipes to those oil fields would have a combined length of less than about 50 km and an average diameter of 20 inches.

Figure 9. Distribution of CO2 from South Sumatera power plant to onshore gas fields.

Table 2 provides a summary of the incremental investment for transmission and distribution of CO2 to the gas fields under various scenarios of utilization. These calculations are based on the pipeline costing factors of US$50,000 per km-inch for on-shore pipelines and US$75,000 per km-inch for off-shore pipelines. Reference [8] provides detailed pipeline design calculations to derive these factors. At the same capture percentage, the West Java power plant has approximately three times more CO2 to be transported than the South Sumatra power plant. As a result, the incremental cost associated with

203

CO2 transportation is considerably higher for West Java than for South Sumatra. Storage Ready CO2 storage ready must comply with at least the following criteria [7]: one or more storage sites have been identified that are technically capable and commercially accessible for geological storage of full volumes of captured CO2 at an acceptable economic cost, adequate capacity, injectivity, and storage integrity have been shown to exist at the storage site(s), any conflicting surface and subsurface land uses at the storage site(s) have been identified and/or resolved. Table 2. Additional Discounted Investments for CO2 Transportation.

Depleted gas fields are considered to be prime locations for the storage of captured CO2 due to the vacant storage volume which is well defined by the quantity of gas that has been produced and the reservoir is well sealed by impermeable rock indicated by the presence of trapped natural gas. A work-over of an old gas well would be required to ensure its integrity, but the ability to use existing wells means that drilling of new wells would probably be avoided. Long-term monitoring of the stored CO2 would be required to ensure permanent retention of CO2. A gas field may become available for CO2 storage when all the gas wells penetrated in that field have reached its economic limit and been abandoned. Figure 10 depicts the gas field locations in West Java and South Sumatera that are available for CO2 storage. Estimated total CO2 storage capacity is also included in the figure. Under storage conditions in a gas field, the CO2 will be a supercritical fluid because the pressure will be above the critical pressure of CO2 and, due to the geothermal gradient, the reservoir temperature will be above the critical temperature of CO2. The density of CO2 and original gas will depend on the reservoir depth. Over the typical range of gas reservoir depths from 800 meters to

204


Figure 10. Gas field locations in West Java and South Sumatera for CO2 storage.

Figure 11. Supply and demand for gas fields CO2 storage in (a) West Java, (b) South Sumater.

2500 meters the average storage capacity factor is 0.0512 MtCO2 per billion standard cubic feet (Bscf) of natural gas produced. This can be used as the default storage factor when the gas reservoir depth is not known. Figure 11 shows the cumulative CO2 storage capacity available in West Java and South Sumatera gas fields and the greatest CO2 production scenarios from both power plants over a number of years. West Java gas fields storage capacity amounts to 395 MtCO2 up to 2050 comprises 224 Mt in 29 off-shore fields plus 171 Mt in 22 on-shore fields. The maximum CO2 production under the condition of 90% capture implemented on both units of West Java power plant from 2025 to the end of design life of the plant in 2045 is 218 Mt. CO2 storage capacity estimated for gas fields in South Sumatera is

around 537 Mt available in 45 fields up to 2050. The cumulative CO2 production assuming that CCS is implemented at 90% capture through the design life of plant from 2027 to 2047 is 74 Mt. These results suggest that the gas fields are technically capable to store captured CO2 under the conditions of the greatest CO2 production scenario. Deep saline aquifers provide additionally around 696 MtCO2 theoretical storage capacity in South Sumatera and 380 MtCO2 in West Java. Therefore, the storage element for definition of CCSR status for both selected power plants could be fulfilled. Monitoring of stored CO2 is a natural part of storage ready. It is aimed to ensure that leakage of CO2 is minimal and any minor leakage is quantified in order to certify the effectiveness of CO2 storage. Additionally, depending on


site-specific considerations, monitoring may be required to ensure that natural resources, such as groundwater and ecosystems, are protected and that the local population is not exposed to unsafe concentrations of CO2. Monitoring of stored CO2 should be tailored to the specific conditions and risks at the storage site [14]. For the case of a storage site which is in a depleted gas reservoir with a well-defined impermeable rock and storage trap, the most likely pathways for leakage are the injection wells themselves or the plugged abandoned wells from previous reservoir operations. The monitoring program should focus on assuring proper performance of all wells and ensuring that they are not leaking CO2 to the surface or shallow aquifers. The cost of monitoring is likely to be on average about US$3.5 per tonne of CO2 stored. In places where existing infrastructure, such as depleted oil and gas fields, are available and can be used for storing CO2, the incremental costs associated with CO2 storage is relatively small. To be conservative, this study assumes an incremental investment of US$3 million per work-over of each depleted well, plus US$1 million per well in potential liabilities, and an additional 8 percent in annual O&M. The corresponding investments are shown in Table 3. A CO2 storage project would require securing rights for land used. Rights to subsurface pore space at the storage sites are owned by the State, which may in turn lease these rights through oil and gas concessions or other grants of authority for limited periods of time. Indonesia’s oil and gas concession practices are well established and extending them to govern CO2 injection represents one possible path to granting rights to pore space. In the oil and gas sector, exploration and exploitation rights take the form of Production Sharing Contracts between oil and gas operators and the Special Task Force for Upstream Oil and Gas Business Activities (SKK Migas). Rights to storage space would similarly require a specific contract from the State or be derived from an existing contract, such as a Production Sharing Contract or other rights grant. The limited time duration of these contractual rights would pose issues for storage of CO2 that must be addressed in advance of any actual project.

205

Table 3. Additional Discounted Investments for CO2 Storage.

CO2 EOR as Cost-Offsetting Mechanism The use of CO2 for EOR presents a potential income stream for CO2 captured from power plants as a cost-offsetting mechanism for CCS projects. It also provides a demonstration of CO2 transportation and storage techniques. Furthermore, from the perspective of the CCS operator, EOR transfers CO2 storage-related liabilities and costs to the oil field operators. EOR has been proven effective in many parts of the world, particularly in the USA [15, 16]. The use of CO2 for EOR is by far the largest potential market for CO2 as a commodity [15]. EOR is not practiced in Indonesia at present, but it is expected that EOR technology will start in the near future. Due to its long history of oil and gas exploration, and the abundance of oil and gas fields, South Sumatra has been identified as an attractive region for EOR [17, 18]. Therefore, assessment of the use of CO2 for EOR in this study was limited in the South Sumatera basin. A total of 127 oil fields as potential sites to use CO2 for EOR in South Sumatera, as shown in Fig. 12, were assessed. Of all the oil fields, 96 oil fields were classified as miscible displacement and the remaining as 31 immiscible process. If it resulted in miscible displacement, then it is assumed it can improve the additional recovery of oil as high as 12% of the original oil in-place (OOIP) but in case of immiscible, the additional recovery is only 5% of the OOIP [18]. The injected CO2 may become miscible or remain immiscible with oil, depending on reservoir pressure, temperature, and oil properties. The miscible CO2 EOR process typically achieves higher oil recoveries than the immiscible process, and therefore, it is a preferred option [19]. Knowing the volume of incremental oil to be produced through miscible and immiscible processes, the pore space available for CO2 can be determined, that is amounts of 243 MtCO2.

206


Experiences indicate that the volume of CO2 needed for a CO2 EOR project changes over a field’s life. Initially the reservoir is flooded with significant amounts of CO2 and it may take time before the effect of the injected CO2 on oil production is seen. After a period of CO2 injection, the produced oil will contain CO2. The CO2 in this oil is separated and thereafter re-injected back into the reservoir. The result is that the field’s need to purchase fresh CO2 is gradually reduced as more and more of the CO2 injected is actually produced with the oil itself. This is illustrated schematically in Figure 13(a) for a typical project [19]. CO2 demand profile with associated oil production for CO2 EOR application on 127 oil fields assessed in South Sumatera is revealed in Figure 13(b). The supply of pure CO2 for EOR in South Sumatera could come from three principal sources [7]: CO2 stripped from natural gas, byproduct CO2 from a proposed SNG plant, and CO2 captured from coal-based power plant flue gas. In contrast to power plant flue gases that contain 10-20% CO2 and require costly and energy intensive separation, the two first sources would only require compression and transport to be ready to use in EOR applications. The availability of these low-cost, ready-touse sources of CO2 that in total are likely to amount to 6 MtCO2/year will impact on the EOR demand for high-cost CO2 captured from coal-based power plant flue gases. An estimated 162 Mt of the demand for CO2 will likely be absorbed by product from low cost CO2 sources. The remaining demand of 81 MtCO2 is only enough to absorb the CO2 captured from the South Sumatera power plant, but insufficient to justify pipelining captured CO2 from West Java power plant to South Sumatera. Revenues from CO2 sales to the oil industry could offset the cost of CO2 abatement on a capital basis associated with CCS. Selling CO2 for EOR under US$ 10 per tonnes CO2 at the gate of the plant would bring the levelized cost of electricity (LCOF) of the South Sumatera plant with 90% CO2 capture down below the ceiling price for geothermal. The LCOF with 45% CO2 capture is down below PLN’s average cost of base load combined-cycle gas turbine (CCGT) plant. Figure 14 provides an illustration of EOR as a cost-offsetting mechanism for CCS.

Figure 12. Oil fields location in South Sumatera relative to coal power plant.

Figure 13. Profiles for CO2 injection and oil production: (a) Typical CO2 EOR project; (b) South Sumatera CO2 EOR Case.

Figure 14. Comparison of coal-based power plant plus CCS with low carbon technologies.

LCOE of Coal-Based Power with CCS Under the 90% capture with no implementation delay scenario, the CCS process will more than double the cost of supply from both reference plants, raising the LCOE from 7.5 US cents/kWh to 16.1 US cents/kWh in West Java, and from 6.4 US cents/kWh to 15.2 US cents/ kWh in South Sumatra. The energy penalty is the key contributor to the incremental cost of CCS, accounting for nearly half of the total incremental cost under the 90% scenario. Table 4 provides a summary of the incremental cost breakdown under


each scenario. Both implementation timing of CCS and capture percentage play important roles with respect to the incremental cost of CCS. Postponing the implementation of CCS by 5 years could help bring the LCOE down to a more affordable level by cutting the incremental cost of CCS by half (from 8.6 to 4.3 US cents per kWh in West Java, and from 8.8 to 4.4 US cents per kWh in South Sumatra). Moreover, postponing CCS implementation would also allow the reference plants to learn from the CCS pilot projects in other places. VI. CONCLUSION Making both the candidate power plants CO2 capture-ready requires additional equipment comprising: SCR, FGD, MEA equipped with LP steam turbo-generator, and C&D for conditioning of CO2. The four major pieces of equipment need to be allocated space on the power plant site. Installation of the equipment would reduce the net electricity delivered to the transmission grid. For the case of 90% CO2 capture resulted in around 27% and 31% reductions in net electricity output for the West Java and South Sumatera power plants. The main cause of electricity output reduction is the net loss due to LP steam use for CO2 capture. Implementation of CCS for both plants will raise the base investment

207

cost significantly as shown in Table 4. Sufficient storage capacity in depleted gas fields has been identified for storage CO2 produced. West Java gas fields storage capacity amounts to 395 MtCO2 that is technically capable to store CO2 production of 218 Mt under the condition of 90% capture from 2025 to 2045. CO2 storage capacity estimated for gas fields in South Sumatera is around 537 Mt which is sufficient to store CO2 production of 74 Mt at 90% capture through the design life of plant from 2027 to 2047. Design and costing for pipelines networks to transport CO2 from the power plant to storage sites have been established. The incremental cost associated with CO2 transportation is considerably higher for West Java than for South Sumatra since the West Java power plant has approximately three times more CO2 to be transported than the South Sumatra power plant. CO2 EOR identified as an attractive cost-offsetting mechanism for CCS projects in the power sector. VII. ACKNOWLEDGMENT The authors wish to thank the World Bank, Research and Development Center for Oil and Gas Technology “LEMIGAS”, and the Indonesian State-Owned Electricity Company, PT. PLN for their research support.

Table 4. West Java and South Sumatera Breakdown of Lcoe.

208


VIII. REFERENCES A. Sugiyono, Anindhita, M.S. Boedoyo, and Adiarso, Indonesia Energy Outlook 2015, Agency for the Assessment and Application of Technology, 2015. Saskpowerccs.com, “Boundary Dam carbon capture and storage project”, [Online]. Available: http:// saskpowerccs.com/ccs-projects/boundary-damcarbon-capture-project/. [Accessed: 31-Jun-2016]. D. Zhou, D. Zhao, Q. Liu, X.C. Li, J. Li, J. Gibbons, and X. Liang, “The GDCCSR project promoting regional CCS-readiness in the Guangdong province, South China,” Energy Procedia 37 (2013): 7622 – 7632. G. P. Hammond and J. Spargo, “The prospects for coal-fired power plants with carbon capture and storage: A UK perspective,” Energy Conversion Management 86 (2014), 476-489. European Academies Science Advisory Council (EASAC), Carbon capture and storgae in Europe, EASAC policy report 20, 2013. Intergovernmental Panel on Climate Change (IPCC), IPCC special report on carbon dioxide and storage, prepared by Working Group III of the IPCC, Cambride University Press, 2005. ICF International, Defining CCS ready: An approach to an internaional definitian, prepared for the Global CCS Institute, 2010. Asian Development Bank, Determining the potential for carbon capture and storage in Southeast Asia: Indonesia Country Report, LEMIGAS/ADB, 2012. T. Masaki, Carbon capture and storage for coal-fired power plants in Indonesia, World Bank Group/ PLN/LEMIGAS, 2015. B.P. Spigarelli and S.K. Kawatra, “Opportunities and challenges in carbon dioxide capture,” J CO2 Utilization, 2013:1, 69-87.

M. Wang, A. Lawal, P. Stephenson, J. Sidders, C. Ramshaw, and H. Yueng, “Post-combustion CO2 capture with chemical absorption: A state-of-theart review,” Chemical Engineering Research and Design, Vol. 89 (9), 1609-1624, 2011. A.S. Bhown and B.C. Freeman, “Analysis and status of post-combustion carbon dioxide capture technologies,” Environ. Sci. Technol., Vol. 45 (20), 8624-8632, 2011. Ecofys, CO2 pipeline infrastructure, prepared for International Energy Agency Greenhouse Gas R&D Programme (IEAGHG) and the Global CCS Institute, 2014. National Energy Technology Laboratory (NETL), Best paractice for: Monitoring, verification, and accounting of CO2 store in deep geological formations, U.S. Department of Energy, 2009. L. Gray and S.G. Goodyear, “Overcoming the CO2 supply challenge for CO2 EOR,” Abu Dhabi International Petroleum Exhibition and Conference, UAE, November 2014. J.E. Faltinson and B. Gunter, “Net CO2 stored in North America EOR projects,” Journal of Canadian Petroleum Technology, Vol. 50 (7), 55-60, 2013. Usman, P.I. Utomo, Sugihardjo, H. Lastiadi, “A systematic approach to source-sink matching for CO2 EOR and sequestration in South Sumatera,” Energy Procedia, Vol. 63 (2014), 7750-7760. Sugihardjo, Usman, and E.M.L. Tobing, “Preliminary carbon utilization and storage screening of oil fields in South Sumatra basin,” Scientific Contribution Oil and Gas, Vol. 35(2), 57-65, 2012. Advanced Resources International Inc. (ARII), Global technology roadmap for CCS in industry: Sectoral assessment CO2 enhanced oil recovery, prepared for United Nations Industrial Development Organization, 2011.

UCAPAN TERIMA KASIH Ucapan terima kasih kepada para Mitra Bestari yang telah mengevaluasi, me-review dan memberikan saran perbaikan tulisan-tulisan yang dimuat di majalah Jurnal Teknologi Minyak dan Gas Bumi (JTMGB) edisi penerbitan Volume 12 Nomor 3, Desember 2016. 1. 2. 3. 4. 5. 6.

Prof. Dr. Ir. Doddy Abdassah, PhD. Prof. Dr. Ir. Septoratno Siregar Dr. Ir. RS Trijana Kartoatmodjo M.Sc. Dr. Ir. Ratnayu Sitaresmi Dr. Ir. Bambang Widarsono Dr. Ir. Arsegianto

INDEKS A G adaptive neuro fuzzy inference system (ANFIS) Gas metana batubara 153, 154 47, 48, 50, 51, 52, 53, 54, 55, 56, 57 geomechanics models 48 Aliran antar-lapisan 177, 178 Anionic Surfactant 185, 188, 189, 190 H artificial intelegence 47, 48 half fracture length 85 hydraulic fracturing 7, 8, 16, 47, 48, 49, 51, 53, B 55, 56, 65, 66, 69, 70, 71, 74, 75, 76, 77, 80, 81, Buckling 1, 2, 5 82, 85, 86, 87, 88, 89, 90, 91, 92, 93, 101, 119, 120, 122, 123, 127, 128, 158 C hydraulic fracturing spacing 85, 101 carbon dioxide 67, 68, 103, 115 carbon dioxide injection 153, 158, 159, 160, 161, I 162, 163, 164 immiscible injection 103 CBM 65, 66, 67, 69, 75, 76, 77, 81, 82, 86, 153, Indonesia 153, 154, 159, 160, 162, 163, 164, 154, 155, 156, 157, 158, 159, 160, 161, 162, 163, 165, 167, 168, 172, 190, 197, 198, 199, 200, 202, 164, 165 205, 207, 208 CCS-ready 197, 198, 199, 203 injection falloff test 23, 24, 25, 26, 27, 28, 29, 30, CO2 27, 33, 37, 38, 39, 40, 41, 42, 43, 44, 45, 46, 33, 34, 35 67, 68, 88, 103, 104, 105, 106, 108, 109, 111, 112, Injeksi Air 168, 177, 178 113, 114, 115, 117 injeksi CO2 153, 167, 168 CO2 capture 197, 198, 199, 200, 201, 202, 205, Injeksi Surfaktan 185, 190 206, 207, 208 injeksi tak bercampur 103, 104 CO2 emissions 197, 198, 199 injeksi tercampur 103, 104, 105, 107, 109 CO2 EOR 168, 172, 197, 205, 206, 207, 208 interfacial tension test 111, 112, 167, 168, 172, CO2 injection 153, 159, 160, 164, 168, 202, 205, 206 186 Coal bed methane 153, 154, 164 coal power plant 197, 198, 199, 206 K computerized model 7, 8 karbon dioksida 103, 104, 105, 106, 108 correlation 21, 23, 37, 44 koefisien gesek 1, 2, 3, 4, 5 Cross Flow 177, 178, 179, 180, 181 korelasi 23, 29, 31, 32, 37, 38, 39, 40, 42, 43, 44 D design hydraulic fracturing 47, 76 Drag 1, 2, 3, 4, 5, 6 Drilling with casing 1, 2, 5, 6 E emisi CO2 197 enhanced recovery 168 EOR 103, 104, 115 equation of state 37, 40 F FOI 119, 120, 124, 127, 128, 150, 151, 152 Friction factor 1

L Laju Alir Produksi 17, 18, 20, 21 Lapangan Tempino 185 metode pendant drop 167, 169 Metode Penjadwalan Proppant 119, 120 M Minimum miscibility pressure 37, 44, 103, 104, 106, 109, 111, 115 miscible injection 103, 109 MMP 103, 104, 105, 106, 107, 108, 109, 111, 115 model geomekanik 47 model komputerisasi 7 model Palmer and Mansoori 23, 25, 27, 29

Natural Dumpflood 177, 178, 179, 180, 181, 182, 183 Non-ionic Surfactant 185, 188 N numerical simulation 37 O Optimisasi 7, 9, 12, 13, 15 Optimization 7, 8, 15, 16, 44 P Palmer and Mansoori model 23, 27 pembangkit listrik batubara 169, 197 penangkapan CO2 197 pendant drop 111, 112, 114 pendant drop method 168 peningkatan perolehan 153, 167, 168, 169 perekahan hidrolik 7, 8, 9, 11, 12, 14, 15, 65, 66 persamaan keadaan 37, 38, 39, 40, 42, 44 Production Rate 17 Proppant 65, 66, 67, 72, 73, 74, 75, 77, 78, 79, 80, 81, 82, 87, 88 Proppant Scheduling Method 119, 120, 123, 127 PSG 119, 120, 126, 127, 133, 150

S shale gas 85, 86, 87, 88, 89, 90, 93, 94, 99, 101, 102 shear sonic 47, 48, 49, 51, 52, 55, 56 simulasi numerik 25, 37, 38, 39, 40, 42, 43 software 7, 8, 13, 15, 26, 28 stress-dependent permeability 23, 24, 25, 26, 27, 28, 32 Surfactan Anionik 185 Surfactant Injection 185, 186, 188, 189, 190, 192, 193 Surfaktan Non-ionik 185 Survei tekanan reservoir 178 Surveillance 177, 178, 180, 181, 182 T tegangan antar muka 111, 112, 113, 114, 115, 117, 167, 169, 170, 171, 173, 174 Tekanan tercampur minimum 37, 38, 44, 109, 111, 112 Tempino Oil Field 185 Torque 1, 5, 6 Torsi 1, 2, 4, 5 V vertical fract 8, 16

R rasio perubahan permeabilitas 23, 25, 29, 30, 31, 32 W Water Coning 17, 18, 20, 21 ratio of permeability change 23 Waterflood 177, 178, 182 Rekah Hidrolik 119, 120 rekahan vertikal 7, 10

JURNAL TEKNOLOGI MINYAK DAN GAS BUMI PEDOMAN PENULISAN ISI DAN KRITERIA UMUM Naskah makalah ilmiah (selanjutnya disebut ”Naskah”) untuk publikasi di Jurnal Teknologi Minyak dan Gas Bumi (JTMGB) dapat berupa artikel hasil penelitian atau artikel ulas balik/tinjauan (review) tentang minyak dan gas bumi, baik sains maupun terapan. Naskah belum pernah dipublikasikan atau tidak sedang diajukan pada majalah/jurnal lain. Naskah ditulis dalam bahasa Indonesia atau bahasa Inggris sesuai kaidah masing-masing bahasa yang digunakan. Naskah harus selalu dilengkapi dengan Abstrak dalam Bahasa Indonesia dan Abstract dalam Bahasa Inggris. Naskah yang isi dan formatnya tidak sesuai dengan pedoman penulisan JTMGB akan dikembalikan ke penulis oleh redaksi untuk diperbaiki. FORMAT Umum. Seluruh bagian dari naskah termasuk judul abstrak, judul tabel dan gambar, catatan kaki, dan daftar acuan diketik satu setengah spasi pada electronic-file dan print-out dalam kertas HVS ukuran A4. Pengetikan dilakukan dengan menggunakan huruf (font) Times New Roman berukuran 12 point. Setiap halaman diberi nomor secara berurutan termasuk halaman gambar dan tabel. Hasil penelitian atau ulas balik/tinjauan ditulis minimum 5 halaman dan maksimum sebanyak 15 halaman, di luar gambar dan tabel. Selanjutnya susunan naskah dibuat sebagai berikut: Judul. Pada halaman judul tuliskan judul, nama setiap penulis, nama dan alamat institusi masing-masing penulis, dan catatan kaki, yang berisikan terhadap siapa korespondensi harus ditujukan termasuk nomor telepon dan faks serta alamat e-mail jika ada. Abstrak. Abstrak/abstract ditulis dalam dua bahasa yaitu bahasa Indonesia dan bahasa Inggris. Abstrak berisi ringkasan pokok bahasan lengkap dari keseluruhan naskah tanpa harus memberikan keterangan terlalu terperinci dari setiap bab. Abstrak tulisan bahasa Indonesia paling banyak terdiri dari 250 kata, sedangkan tulisan dengan bahasa Inggris maksimal 200 kata. Kata kunci/keywords ditulis di bawah abstrak/abstract dan terdiri atas tiga hingga lima kata. Pendahuluan. Bab ini harus memberikan latar belakang yang mencukupi sehingga pembaca dapat memahami dan dapat mengevaluasi hasil yang dicapai dari penelitian yang dilaksanakan tanpa harus membaca sendiri publikasi-publikasi sebelumnya, yang berhubungan dengan topik yang bersangkutan. Permasalahan. Bab ini menjelaskan permasalahan yang akan dilakukan penelitian ataupun kajian. Metodologi. Berisi materi yang membahas metodologi yang dipergunakan dalam menyesaikan permasalahan melalui penelitan atau kajian. Hasil dan Analisis. Hanya berisi hasil-hasil penelitian baik yang disajikan dengan tulisan, tabel, maupun gambar. Hindarkan penggunaan grafik secara berlebihan bila dapat disajikan dengan tulisan secara singkat. Batasi penggunaan foto, sajikan yang benar-benar mewakili hasil penemuan. Beri nomor gambar dan tabel secara berurutan. Semua gambar dan tabel yang disajikan harus diacu dalam tulisan. Pembahasan atau Diskusi. Berisi interpretasi dari hasil penelitian yang diperoleh dan pembahasan yang dikaitkan dengan hasil-hasil yang pernah dilaporkan. Kesimpulan dan Saran. Berisi kesimpulan dan saran dari isi yang dikandung dalam tulisan. Kesimpulan atau saran tidak boleh diberi penomoran. Ucapan Terima Kasih. Bila diperlukan dapat digunakan untuk menyebutkan sumber dana penelitian dan untuk memberikan penghargaan kepada beberapa institusi atau orang yang membantu dalam pelaksanaan penelitian dan atau penulisan laporan.

JURNAL TEKNOLOGI MINYAK DAN GAS BUMI PEDOMAN PENULISAN DAFTAR PUSTAKA Acuan. Acuan ditulis dan disusun menurut abjad. Beberapa contoh penulisan sumber acuan: Jurnal Hurst, W., 1934. Unsteady Flow of Fluids in Oil Reservoirs. Physics (Jan. 1934) 5, 20. Buku Abramowitz, M and Stegun, I.A., 1972. Handbook of Mathematical Functions. Dover Publications, Inc., New York. Bab dalam Buku Costa, J.E., 1984. Physical geomorphology of debris flow. Di dalam: Costa, J.E. & Fleischer, P.J. (eds), Developments and Applications of Geomorphology, Springer-Verlag, Berlin, h.268-317. Abstrak Barberi, F., Bigioggero, B., Boriani, A., Cavallini, A., Cioni, R., Eva, C., Gelmini, R., Giorgetti, F., Iaccarino, S., Innocenti, F., Marinelli, G., Scotti, A., Slejko, D., Sudradjat, A., dan Villa, A., 1983. Magmatic evolution and structural meaning of the island of Sumbawa, Indonesia-Tambora volcano, island of Sumbawa, Indonesia. Abstract 18th IUGG I, Symposium 01, h.48-49. Peta Simandjuntak, T.O., Surono, Gafoer, S., dan Amin, T.C., 1991. Geologi Lembar Muarabungo, Sumatera. Pusat Penelitian dan Pengembangan Geologi, Bandung. Prosiding Marhaendrajana, T. and Blasingame, T.A., 1997. Rigorous and Semi-Rigorous Approaches for the Evaluation of Average Reservoir Pressure from Pressure Transient Tests. paper SPE 38725 presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 5–8. Skripsi/Tesis/Disertasi Marhaendrajana, T., 2000. Modeling and Analysis of Flow Behavior in Single and Multiwell Bound ed Reservoir. PhD dissertation, Texas A&M University, College Station, TX. Informasi dari Internet Cantrell, C., 2006. Sri Lankan’s tsunami drive blossom: Local man’s effort keeps on giving. Http:// www.boston.com/news/local/articles/2006/01/26/sri_lankans_tsunami_drive_blossoms/[26 Jan 2006] Software ECLIPSE 100 (software), GeoQuest Reservoir Technologies, Abbingdon, UK, 1997. Naskah sedapat mungkin dilengkapi dengan gambar/peta/grafik/foto. Pemuatan gambar/peta/grafik/foto selalu dinyatakan sebagai gambar dan file image yang bersangkutan agar dilampirkan secara terpisah dalam format image (*.jpg) dengan ukuran minimal A4 dan minimal resolusi 300 dpi, Corel Draw (*,cdr), atau Autocad (*,dwg). Gambar dan tabel diletakkan di bagian akhir naskah masing-masing pada halaman terpisah. Gambar dan tabel dari publikasi sebelumnya dapat dicantumkan bila mendapat persetujuan dari penulisnya. PENGIRIMAN Penulis diminta mengirimkan satu eksemplar naskah asli beserta dokumennya (file) di dalam compact disk (CD) yang harus disiapkan dengan program Microsoft Word. Pada CD dituliskan nama penulis dan nama dokumen. Naskah akan dikembalikan untuk diperbaiki jika persyaratan ini tidak dipenuhi. Naskah agar dikirimkan kepada: Redaksi Jurnal Teknologi Minyak dan Gas Bumi d.a. Patra Office Tower Lt. 1 Ruang 1C Jln. Jend. Gatot Subroto Kav. 32-34 Jakarta 12950 – Indonesia Pengiriman naskah harus disertai dengan surat resmi dari penulis penanggung jawab/korespondensi (corresponding author) yang harus berisikan dengan jelas nama penulis korespondensi, alamat lengkap untuk surat-menyurat, nomor telepon dan faks, serta alamat e-mail dan telepon genggam jika memiliki. Penulis korespondensi bertanggung jawab atas isi naskah dan legalitas pengiriman naskah yang bersangkutan. Naskah juga sudah harus diketahui dan disetujui oleh salah satu penulis dan atau seluruh anggota penulis dengan pernyataan secara tertulis.

ISSN 021664101-2 ISSN 0216-6410

9

7 7 0 2 1 6

6 4 1 0 1 4

Jurnal Teknologi Minyak dan Gas Bumi

Recommend Documents