Modular Formation Dynamics Tester (MDT) adalah salah satu alat Wireline Formation Tester (WFT) yang memberikan pengukuran tekanan, permeabilitas dan permeabilitas anisotropi yang akurat dan cepat, analisis sampling fluida dan analisis fluida lubang bawah, dan fracture mikro hidrolik. Dengan menggunakan teknologi pengujian pembentukan yang sangat maju dan mapan, alat ini dapat memberikan informasi karakterisasi reservoir dan mengukur tekanan statis. Dalam satu kali pengambilan sampel dari lubang sumur, alat MDT dapat mengumpulkan sejumlah besar sampel cairan formasi representatif untuk informasi secara akurat dan tepat waktu. Ditambah dengan data-data lubang sumur yang lain, semuanya digunakan untuk mengidentifikasi interval zona hidrokarbon secara meyakinkan. Dengan menggunakan contoh dari lapangan, makalah ini membahas bagaimana analisis tekanan pasca-MDT dapat digunakan untuk menentukan produktivitas zonal. Produktivitas zonal dari MDT ini kemudian dibandingkan dengan produktivitas uji coba konvensional. Perangkat lunak Pansys dari Edinburgh Petroleum Services (EPS) Ltd telah digunakan untuk menganalisis contoh data data MDT dan juga data pengujian sumur. Hasil penelitian ini menunjukkan bahwa ada korelasi yang erat antara perkiraan indeks produktivitas MDT dan uji coba sumur konvensional. Oleh karena itu, metode ini dapat menghilangkan kebutuhan akan zona yang diuji secara konvensional untuk menentukan produktivitas zona hidrokarbon.
Tujuan pengoptimalan pengeboran adalah untuk mengurangi biaya, meningkatkan kondisi lubang sumur dan integritas reservoir, dengan tetap mengutamakan kinerja keselamatan maksimum dan pemeliharaan lingkungan. Meskipun hasil akhir dari suatu operasi pengeboran mudah diamati, akan tetapi yang hampir sering luput dari perhatian adalah kompleksitas masalah dalam perencanaan dan pelaksanaan operasi Pengeboran. Dalam tulisan ini telah dievaluasi studi kasus pemboran eksplorasi di salah satu basin di Afrika Utara. Selama periode 2006 hingga 2011, peningkatan pengeboran yang berkelanjutan telah dicapai. Elemen kunci dalam optimasi tersebut meliputi fokus pada struktur manajemen team pemboran, perencanaan rekayasa/teknik sumur, perbaikan dalam pengelolaan operasi pemboran seperti praktek manajemen keselamatan di lokasi, dan juga analisis pasca pengeboran untuk mengimplementasikan pembelajaran untuk sumur berikutnya yang akan dibor. Hasilnya, selama pemboran 26 sumur selama tahun 2006 hingga 2011, hari pemboran berhasil dikurangi dari 87 hari (sumur pertama) menjadi rata-rata 40 hari, dengan kemampuan deliverable produksi sumur yang tinggi, juga kinerja catatan keselamatan yang sangat baik.
At northern part of Sumatera Indonesian onshore many drilling issues were encounteredin the area, in particular the overlying shales above the pay zones in the high deviatedtrajectory wells. Since the last well drilling in this area was 70’ era, so that limited data isanother drilling engineering challenge, especially to provide an accurate drilling fluid. Tocombat the drilling issues, utilization of pre-treated wellbore strengthening agent wasapplied to reduce well bore issues and strengthen the well with an effective filter cake. In Northern Sumatera Indonesian onshore well in Indonesia was used as a case study. First a brief understanding and fundamentals of geo-mechanics is described in reference to wellconstruction as well as filter cake fundamental to protect the hole stability. Results,observations and conclusions were drawn upon using a case study comparing a well ononshore in Indonesia which had many drilling problems such as stuck pipe/differentialsticking and washouts/hole enlargement issues related to well bore stability, after using thewellbore stability agent, the problems that encountered significantly decrease.
Drilling optimization objective was to reduce costs, improve wellbore conditions and integrity for increasingly challenging reservoirs while establishing maximum safety performance and environmental custodianship. Even though the final result of a drilling operation is easily observed, what almost always goes unnoticed is the complexity of the issues involved in the planning and execution of a drilling operation and the number of topics involved in such a process. In this paper, as case study of the exploration drilling in Hamada region, North Africa has been evaluated. Over the period of 2006 to 2011, continued drilling improvement was achieved. Key elements in the optimization included focus on management drilling team structure, engineering well planning, improvements on managing drilling operations such as on site safety management practices, and also post drill analysis to implement lesson learn for the next well to be drilled. As the result, while drilling 26 wells during the 2006 until 2011, drilling days were successfully reduced from 87 days (first well) to the average 40 days, and very good safety record performance. Keywords : optimization, drilling cost, drilling performance
Well X is located in the offshore Y field, where there are 7 production wells, all of which use an artificial lift in the form of a gas lift. In this field, oil is produced from the N oil layer while the gas layer comes from the K layer. Well X was drilled in May 2013 with a target of N oil formation at a depth of 9,007 ft MD, slope (450) and 4-1/2" Liner completion. The initial production of well X was 1,632 BOPD; 5.3 MMSCFD; 0% BSW. Well X is the only well in the Y offshore field that does not penetrate the K gas formation, so gas production from nearby wells is used to produce oil from the N formation. well-to-well gas lift. Along with production time, the reservoir pressure in the N oil layer and K gas layer has decreased, so that oil production in well X has also decreased. With changes in company policy that optimize and increase gas production to increase gas sales to the industry around the company's operational areas since early 2017, the outgoing pressure on the Y platform has increased from 210 psi to 450 psi, causing a total oil well X could not pass through and produce due to high outgoing pressure on platform Y. Well X's last production data was on January 31 2017 with oil production of 179 BOPD and 1.25 MMSCD for gas production and gas lift injection of 0.75 MMSCFD, before finally shutting down. The selection of another artificial lift as a substitute for the gas lift has been carried out to revive well X later. Based on the alloy table made by Weatherford for the selection of artificial lifts for conditions on the Y field platform, ESP has many advantages and appropriate flexibility compared to other types of artificial lifts. The ESP type D1050N which is a mix flow ESP has been selected and after installation in well X in August 2019 it has successfully revived with a production test of 885 BFPD, 681 BOPD, and 23% water content on September 3 2019. ESP in well X has been in production for 2 years, until finally experiencing a leaky tubing problem in September 2021 and requiring a new tubing replacement job along with a new ESP replacement to revive the X well. Reference: Brown, E., Kermit, (1977). The Technology of Artificial Lift Method”, Volume 2a, Oklahoma; Pennwell Publishing Company. Brown, E., Kermit (1980). The Technology of Artificial Lift Method”, Volume 3a, Oklahoma; Pennwell Publishing Company. Data-data Lapangan Sumur X Lapangan Offshore Y. (2019-2021). Gabor, Takack. (2009). Electric Submersible Pump Manual Desingn, Operations and Maintenance. United States of America: Gulf Publishing Company. Weatherford. (2005). Artificial Lift System.
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