Articles
<![CDATA[STUDY OF ENHANCED OIL RECOVERY WITH ALKALINE SURFACTANT POLYMER INJECTION METHOD BY USING LABORATORY TEST ]]>
<![CDATA[Edward ML Tobing]]>;
<![CDATA[Hestuti Ani]]>
<![CDATA[ Scientific Contributions Oil and Gas Vol. 37 No. 3 (2014): SCOG ]]>
Publisher : <![CDATA[Testing Center for Oil and Gas LEMIGAS ]]>
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DOI: 10.29017/scog.37.3.228
<![CDATA[One effort to improve oil recovery in oil reservoirs after primary and secondary recovery period is to apply the method of Enhanced Oil Recovery (EOR). Screening of EOR on the characteristics of the reservoir rock and Àuid 'N' indicates that the suitable method is the injection of alkali surfactant polymer (ASP). This paper presents the results of laboratory tests to increase the oil recovery in the reservoir 'N' with ASP injection. The purpose of the laboratory testing was to determine the additional oil recovery by injecting a solution of ASP in the reservoir rock 'N'. Based on the results of compatibility, interfacial tension, rheology, thermal stability, filtration and static adsorption test on an ASP Àuid injection, the optimum concentration of each of the injection Àuid is obtained. Referring to the optimum concentration of the ASP, then the core Àooding test design based on a predetermined Àuid injection. The main result of the Àooding test cores showed an increase in oil recovery as much as 21.84% OOIP. When the results of the laboratory test was applied to the field scale by injecting Àuid into the reservoir ASP 'N', then the estimated potential increase in oil production as much as 11.457 million bbl.]]>
<![CDATA[EFFECT OF OPTIMUM SALINITY?ON MICROEMULSION FORMATION TO ATTAIN ULTRALOW INTERFACIAL TENSION FOR CHEMICAL FLOODING APPLICATION ]]>
<![CDATA[Yani Faozani Alli]]>;
<![CDATA[Edward ML Tobing]]>
<![CDATA[ Scientific Contributions Oil and Gas Vol. 39 No. 2 (2016): SCOG ]]>
Publisher : <![CDATA[Testing Center for Oil and Gas LEMIGAS ]]>
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DOI: 10.29017/scog.39.2.263
<![CDATA[Microemulsion formation in surfactant solution has a major influence on the success of chemical injection techniques, and is one of the enhanced oil recovery methods. Its transparent and translucent homogenous mixtures of oil and water in the presence of surfactant have an ability to displace the remaining oil in the reservoir by reducing interfacial tension between oil and water. In this study, the effect of surfactant solution salinity on the formation of microemulsion and its mechanism to reduce the interfacial tension between water and oil from X oil field in Central Sumatera were carried out through compatibility observation, phase behaviour test and interfacial tension measurements in a laboratory. The results showed that microemulsion formation depends on the salinity of aqueous phase associated with different surfactant solubility by altering the polar area of surfactant. The optimum salinity was obtained with the addition of 0.65% Na2CO3 in which microemulsion was formed and the solubilization ratio of oil and water were equally high. At this condition the ultralow interfacial tension was around 10-3 dyne/cm and enabled improved oil recovery in mature oil fields after waterflooding]]>
<![CDATA[MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION ]]>
<![CDATA[Yani Faozani Alli]]>;
<![CDATA[Edward ML Tobing]]>;
<![CDATA[Usman]]>
<![CDATA[ Scientific Contributions Oil and Gas Vol. 40 No. 2 (2017): SCOG ]]>
Publisher : <![CDATA[Testing Center for Oil and Gas LEMIGAS ]]>
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DOI: 10.29017/scog.40.2.287
<![CDATA[The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.]]>
<![CDATA[A Single Phase Model For Analyzing Gas Pipeline Networks ]]>
<![CDATA[Edward ML Tobing]]>
<![CDATA[ Scientific Contributions Oil and Gas Vol. 31 No. 3 (2008): SCOG ]]>
Publisher : <![CDATA[Testing Center for Oil and Gas LEMIGAS ]]>
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<![CDATA[A single phase flow model has been developed for gas distribution pipeline networks.The model is developed based on looped-system approach with some modifications. In thismodel, a equation of State model is implemented for predicting the gas properties requiredfor the goveming equations of the network system. By utilizing the Linear Theory Method,the Panhandle’s single phase gas flow model is implemented in this model to predict thehydrodynamic variables in each leg of the network using the iterative technique which isdeveloped in this study. A generalization of the single phase network model is providedthereby making it possible for the single flow model used to be replaced by another onethat may be rnore applicable for a particular situation. Using the iterative procedure devel-oped, pressure at all nodes, gas flow rate at each leg can be predicted. The test resultsdemonstrate that the model can serve as a predictive and design tool for solving a singlephase gas flow problem in pipeline network.]]>
<![CDATA[Changing Wellbore Storage In Gas Well Testing ]]>
<![CDATA[Edward ML Tobing]]>
<![CDATA[ Scientific Contributions Oil and Gas Vol. 31 No. 2 (2008): SCOG ]]>
Publisher : <![CDATA[Testing Center for Oil and Gas LEMIGAS ]]>
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<![CDATA[Extended wellbore storage can be mistakenly interpreted as a reservoir response in gaswell testing with surface shut in. This interpretation usually results in false value for per-meability, skin and reservoir si:e and shape. This paper investigates changing wellbore storage in pressure transient testing withsurface shut-in in gas well. This study was prompted by the observation, that in gas wells,rnany of the buildup tests obtained with surface shut-in exhibited complex reservoir modelbehavior with relatively low skin. The results presented in this paper are based on well test simulation and field data fromNorth Sumatera. This work demonstrates the effect changing wellbore storage on the pres-sure derivative curve. Knowledge of the expected pressure derivative shape, and duration,will improve the design of buildup tests that will allow enough tirne for the actual reservoirresponse to be observed. This will result in a reliable reservoir model and correct estima-tion of permeability and skin factor.]]>
<![CDATA[Penentuan Tekanan Tercampur Minimum Injeksi CO2 Melalui Model Simulasi Slim Tube EOR ]]>
<![CDATA[Edward ML Tobing]]>
<![CDATA[ Lembaran Publikasi Minyak dan Gas Bumi Vol. 56 No. 1 (2022): LPMGB ]]>
Publisher : <![CDATA[BBPMGB LEMIGAS ]]>
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<![CDATA[Injeksi CO2 ke dalam reservoir minyak dikenal sebagai salah satu metode Enhanced Oil Recovery (EOR) yang telah terbukti dan cukup efektif menurunkan jumlah minyak yang tertinggal di dalam reservoir. CO2 dan minyak akan tercampur bila tekanan injeksi CO2 mencapai tekanan tercampur minimum (TTM). Untuk mengetahui TTM tersebut dapat diperoleh dari uji laboratorium dengan menginjeksikan CO2 pada alat slim tube. Pada penelitian ini dilakukan uji laboratorium slim tube dengan menginjeksikan 100% Mol CO2 dan MMP yang diperoleh 2400 psig. Kendala untuk dapat mencapai TTM tersebut adalah tekanan reservoir rendah karena minyak yang diproduksikan sudah lama dan pada umumnya tekanan rekah formasi lebih rendah dari TTM. Untuk menyiasati hal tersebut, fluida injeksi CO2 dicampur dengan gas bumi untuk dapat menurunkan TTM. Kemudian dikembangkan model simulasi numerik injeksi CO2 pada slim tube dengan menggunakan data uji slim tube di laboratorium. TTM yang diperoleh dari model simulasi numerik slim tube adalah 2385 psig. Dengan model simulasi numerik slim tube tersebut kemudian dilakukan injeksi pada berbagai komposisi campuran CO2 dan gas bumi untuk mengetahui seberapa besar penurunan MMP. Untuk campuran fluida injeksi 60% Mol CO2 dan 40% mol gas bumi MMP diperoleh 2100 psig, sehingga dapat menurunkan MMP sebesar 285 psig dibandingkan dengan menginjeksikan 100% Mol CO2.]]>
<![CDATA[UJI SENSITIVITAS KONSENTRASI SURFAKTAN POLIMER DAN VOLUME SLUG TERHADAP PEROLEHAN MINYAK MELALUI MODEL SIMULASI POLA SUMUR INJEKSI PRODUKSI EOR ]]>
<![CDATA[Edward ML Tobing]]>
<![CDATA[ Lembaran Publikasi Minyak dan Gas Bumi Vol. 52 No. 1 (2018): LPMGB ]]>
Publisher : <![CDATA[BBPMGB LEMIGAS ]]>
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<![CDATA[Salah satu metode enhanced oil recovery (EOR) untuk meningkatkan produksi dari lapangan minyak tua adalah melalui injeksi surfaktan polimer, yang berfungsi dapat menurunkan tegangan antar muka dan perbandingan mobilitas air-minyak. Karya tulis ini memfokuskan pada pengembangan model simulasi reservoir injeksi kimia surfaktan polimer, yaitu dengan melakukan scale-up berdasarkan model simulasi hasil uji pendesakan (core flooding) injeksi surfaktan polimer di laboratorium. Model simulasi reservoir yang telah dikembangkan tersebut mempunyai bentuk pola sumur injeksi produksi half inverted 7 spot dengan dimensi 8x17x35. Kondisi inisial reservoir terdiri dari: saturasi minyak tersisa dan saturasi air masing masing sebesar 35.0% dan 65.0%, serta suhu 61oC. Berdasarkan injeksi surfaktan polimer dengan masing masing konsentrasi sebesar 0.30% berat dan 0.260% berat serta ukuran slug injeksi surfaktan-polimer sebanyak 0.164 pore volume pada model diatas, menunjukkan potensi penambahan perolehan minyak 33.52% original in place dari saturasi minyak tersisa. Uji sensitivitas dilakukan dengan menambahkan maupun mengurangi konsentrasi surfaktan dan polimer serta ukuran slug injeksi surfaktan-polimer melalui model simulasi tersebut. Hasil yang didapat menunjukkan potensi penambahan perolehan minyak yang optimal sebesar 46.03% original in place dari saturasi minyak tersisa, dengan ukuran slug injeksi surfaktan-polimer 0.205 pore volume serta masing masing konsentrasi surfaktan-polimer 0.435% berat dan 0.234% berat.]]>
<![CDATA[STUDI KELAYAKAN UNTUK IMPLEMENTASI INJEKSI CO2 SKALA PILOT DI LAPANGAN MINYAK A, SUMATERA SELATAN ]]>
<![CDATA[Dadan DSM Saputra]]>;
<![CDATA[Sugihardjo]]>;
<![CDATA[Edward ML Tobing]]>
<![CDATA[ Lembaran Publikasi Minyak dan Gas Bumi Vol. 52 No. 1 (2018): LPMGB ]]>
Publisher : <![CDATA[BBPMGB LEMIGAS ]]>
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<![CDATA[Injeksi CO2-Enhanced Oil Recovery (EOR) di lapangan minyak mature Indonesia untuk meningkatkan produksi minyak perlu segera diaplikasikan. Selain untuk meningkatkan produksi minyak, injeksi CO2-EOR juga digunakan untuk mengurangi emisi gas CO2 di atmosfer. Pemerintah perlu mengaplikasikan Carbon Capture Utilization and Storage (CCUS) untuk dapat mengurangi emisi gas rumah kaca (GRK) sesuai dengan RUEN dan INDC Indonesia yaitu sebesar 29% pada tahun 2030. Tujuan dilakukannya studi ini untuk mengkaji kelayakan dari proyek implementasi injeksi CO2 skala pilot di Lapangan Minyak A. Studi ini fokus pada studi kelayakan injeksi CO2 skala pilot di Lapangan Minyak A Lapisan Y Blok D di daerah Sumatera Selatan dimulai dari proses screening lapangan minyak untuk injeksi CO2, studi Geologi Geofisika dan Reservoir (GGR) serta analisis keekonomian yang mencakup skenario transportasi CO2 dari sumber CO2 ke lokasi injeksi. Dari hasil simulasi reservoir didapatkan bahwa injeksi CO2 secara dengan laju alir sebesar 150 ton per hari selama 5 tahun (dimulai dari awal 2017) dapat meningkatkan perolehan minyak menjadi 4,7% IOIP (dengan basecase 2% IOIP), sedangkan dengan menggunakan laju alir 75 ton per hari dapat meningkatkan sebesar 3,37% IOIP pada daerah prospek di Lapisan Y Blok D. Dari hasil analisis keekonomian, harga jual CO2 terendah diperoleh dari skenario II (transportasi menggunakan truk) sebesar US$48,13 per ton CO2 dan akan layak untuk diinjeksikan pada saat harga minyak lebih dari US$83 per barel.]]>
<![CDATA[PENENTUAN TEKANAN TERCAMPUR MINIMUM INJEKSI CO2 MELALUI MODEL SIMULASI SLIM TUBE EOR ]]>
<![CDATA[Edward ML Tobing]]>
<![CDATA[ Lembaran Publikasi Minyak dan Gas Bumi Vol. 52 No. 2 (2018): LPMGB ]]>
Publisher : <![CDATA[BBPMGB LEMIGAS ]]>
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<![CDATA[Injeksi CO2 ke dalam reservoir minyak dikenal sebagai salah satu metode Enhanced Oil Recovery (EOR) yang telah terbukti dan cukup efektif menurunkan jumlah minyak yang tertinggal di dalam reservoir. CO2 dan minyak akan tercampur bila tekanan injeksi CO2 mencapai tekanan tercampur minimum (TTM). Untuk mengetahui TTM tersebut dapat diperoleh dari uji laboratorium dengan menginjeksikan CO2 pada alat slim tube.]]>
<![CDATA[SIMULASI PERCOBAAN COREFLOODING INJEKSI SURFAKTAN POLIMER PADA BATUAN RESERVOIR ]]>
<![CDATA[Edward ML Tobing]]>
<![CDATA[ Lembaran Publikasi Minyak dan Gas Bumi Vol. 50 No. 1 (2016): LPMGB ]]>
Publisher : <![CDATA[BBPMGB LEMIGAS ]]>
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<![CDATA[Dalam beberapa tahun belakangan ini injeksi surfaktan-polimer banyak diterapkan untuk dapat meningkatkanproduksi lapangan minyak tua, karena mempunyai efek sinergis dari penurunan tegangan antar muka dankontrol mobilitas dengan efek samping yang minimal.]]>
