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Ditemukan: 16 dokumenEVALUASI EFISIENSI PENYIMPANAN CO2 DINAMIS PADA AKUIFER SALIN DENGAN MEMPERTIMBANGKAN KENDALA GEOMEKANIKA
As Indonesia accelerates decarbonization efforts to achieve Net Zero Emissions by 2060, Carbon Capture and Storage in deep saline aquifers has emerged as a critical technological pathway. This study tries to generalize a case study evaluation of the Sunda-Asri Basin’s Talang Akar Formation by determining a geomechanically constrained dynamic storage efficiency factor (Esaline) derived from published data and regional analogs, yielding a proposed systematic evaluation flowchart. Initially, a probabilistic Monte Carlo simulation was conducted as a rapid realization check, yielding a P50 theoretical static capacity of 11.96 Mt CO2, which was adjusted to 0.24 Mt after accounting for a 2% theoretical efficiency assumption. Subsequently, the initialization of a compositional 3D reservoir model yielded a theoretical storage capacity of 12.16 Mt CO2. The analytical results reveal a significant discrepancy between these static approaches, while the Monte Carlo and 3D models identify the theoretical storage ceiling, dynamic modeling strictly limits injectivity to 0.192 Mt CO2. Crucially, by evaluating the influence of geomechanics, the integration of realistic rock mechanics (Young’s Modulus and Poisson’s Ratio) to prevent induced caprock failure further curtailed the capacity to a final dynamic storage of 0.100 Mt CO2, yields a risk-averse dynamic efficiency factor of 0.82%. Extrapolating this rigorous metric to the basin’s 3 Gt theoretical capacity confirms a practical regional storage potential of 24.65 Mt CO2. Ultimately, the consistent hierarchy observed between static, dynamic, and geomechanically constrained models validates this systematic methodology as a robust generalized framework for mitigating subsurface uncertainty and advancing national strategic energy objectives.
ANALISIS GEOMEKANIKA UNTUK PEREKAHAN HIDROLIK PADA FORMASI TELISA, LAPANGAN TULIP, CEKUNGAN SUMATRA SELATAN
Lapangan Tulip merupakan salah satu lapangan produksi minyak dan gas yang dioperasikan oleh PT Medco E&P Indonesia, secara administratif terletak di Kabupaten Musi Banyuasin, Provinsi Sumatra Selatan. Lapangan ini berada pada Sub-Cekungan Palembang Selatan, Cekungan Sumatra Selatan, dengan interval reservoir utama pada Formasi Telisa dengan properti reservoir permeabilitas (rata-rata 5,5 mD pada batupasir dan 2,1 mD pada batulempung), porositas efektif berkisar 18,1%, dan heterogenitas yang tinggi. Penelitian ini bertujuan membangun model geomekanika satu dimensi (1D) dan tiga dimensi (3D) untuk menentukan rezim tegasan saat ini, menghitung tegasan rekah untuk keperluan perekahan hidrolik, serta menentukan distribusi rekahan pada interval Formasi Telisa. Pemodelan geomekanika dilakukan menggunakan pendekatan poroelastik (Blanton dan Olson, 1999) untuk estimasi tegasan horizontal, dengan kalibrasi menggunakan data FCP dan ISIP dari laporan perekahan hidrolik. Hasil model 1D menunjukkan rata-rata gradien tegasan: Sv = 0,967 psi/ft, Shmin = 0,728 psi/ft, SHMax = 0,786 psi/ft, dan tekanan pori = 0,44 psi/ft. Pola tegasan ini mengindikasikan rezim sesar normal (Sv > SHMax > Shmin). Interpretasi struktur pada penampang seismik mengidentifikasi negative flower structure dengan tren sesar dominan berarah NNW–SSE (315–345°), yang merupakan hasil strain partitioning dari sesar geser berarah NW–SE sebagai PDZ utama. Lapangan Tulip terletak pada zona transtensional (releasing bend) dari sistem strike-slip tersebut, dibatasi oleh Tinggian Palembang di sisi barat dan Jemakur Graben di bagian timur. Model geomekanika 3D statis dibangun menggunakan properti mekanika batuan yang tersebar secara lateral melalui tren atribut inversi seismik. Hasil distribusi model 3D menunjukkan adanya stress barrier pada lapisan batulempung Telisa, yang berperan sebagai penahan tinggi rekahan. Nilai tekanan rekah minimum pada interval target rata-rata sebesar 1.680 psi. Rekomendasi zona target perekahan hidrolik berada pada daerah N-NNE yang ditentukan berdasarkan penggabungan parameter Brittleness Index (BI) dan tegasan horizontal minimum, dengan kriteria BI > 0,4 dan Shmin < 1.680 psi.
DESAIN PERLAKUAN PROPPANT REKAHAN HIDRAULIK PADA ZONA TERPILIH DI FORMASI GL-E: STUDI KASUS SUMUR XX UNTUK MENINGKATKAN PERFORMA PRODUKSI
Global gas demand continues to rise, positioning natural gas as a cleaner fossil fuel in the transition towards low-carbon energy systems. To meet this demand, tight gas reservoirs have become increasingly important, yet many of these formations cannot deliver sufficient rates without stimulation. Hydraulic fracturing is widely recognized as an essential stimulation technique to improve well productivity that overcomes those challenges. This study investigates the GL-E formation of XX Well in the BB Field, Natuna Sea, which is known to present challenging conditions. A geomechanical evaluation was carried out to determine the most favorable zone for fracturing treatment. Based on the integration of geomechanical parameters, the GL-E2 zone was identified as the optimal target because it combines higher Young’s modulus, lower Poisson’s ratio, and greater thickness compared to the other zones, indicating brittleness and fracture potential. Fracturing design and simulation were then performed with sensitivity analysis by varying the type and total mass of proppant. The results demonstrate that resin-coated sand (RCS) proppant at 220,000 lbs yields the most effective treatment scenario, achieving higher productivity improvement with a favorable cost-to-performance balance compared to ceramic proppant alternatives. Post-treatment evaluation through nodal analysis shows a substantial increase in gas production rate, from 4.84 MMscf/d to 16.85 MMscf/d. The findings emphasize that geomechanical screening and fracture design treatment can significantly enhance well productivity.
PEMODELAN GEOMEKANIKA SATU DIMENSI UNTUK EVALUASI KESTABILAN LUBANG BOR DAN PENENTUAN LOKASI INJEKSI CCS DI LAPANGAN OJ, CEKUNGAN SUMATRA SELATAN
Lapangan OJ merupakan lapangan penghasil hidrokarbon produktif yang terletak pada Sub-Cekungan Jambi, Cekungan Sumatra Selatan. Lapangan ini sudah berproduksi cukup lama dan mulai menuju tahap deplesi pada reservoarnya, sehingga injeksi CO2 Capture and Storage (CCS) merupakan langkah yang baik agar lapangan tetap ekonomis sekaligus mengurangi emisi karbondioksida dalam upaya menuju Net Zero Emission (NZE). Cekungan Sumatra Selatan memiliki rezim tektonik yang kompleks dan memiliki zona overpressure, oleh karena itu analisis geomekanika diperlukan untuk mengetahui kondisi tegasan in situ, menganalisis rezim tegasan, mengevaluasi strategi pengeboran, dan menentukan rekomendasi area injeksi CCS yang aman dari reaktivasi sesar di Lapangan OJ. Penelitian ini dilakukan pada sumur T-4. T-3, dan T-2 menggunakan data log talikawat, laporan pemboran, log gambar (FMI), beberapa data seismik, dan peta kedalaman struktur interval reservoar. Data log talikawat diolah menjadi model geomekanika satu dimensi yang kemudian dianalisis dan diintegrasi pada persebaran sesar di Lapangan OJ menjadi hipotesis kestabilan sesar. Hasil dari pemodelan geomekanika satu dimensi menunjukkan bahwa Lapangan OJ memiliki arah tegasan horizontal maksimum sebesar N50oE dengan dua tren tegasan utama, yaitu saat kondisi tekanan hidrostatik dan kondisi overpressure. Pada kondisi hidrostatik, gradien geomekanika memiliki profil tekanan pori 0.44 psi/ft, tegasan vertikal sebesar 0.91 psi/ft, tegasan horizontal minimum sebesar 0.86 psi/ft, tegasan horizontal maksimum sebesar 1.45 psi/ft. Pada kondisi overpressure, gradien geomekanika memiliki profil tekanan pori sebesar 0.478 psi/ft, tegasan vertikal sebesar 0.915 psi/ft, tegasan horizontal minimum sebesar 0.881 psi/ft, dan tegasan horizontal maksimum sebesar 1.49 psi/ft. Lapangan OJ berada pada rezim sesar geser yang kritis terhadap sesar naik (SHmax > SV ? Shmin) dan rezim sesar geser (SHmax > SV > Shmin). Berat lumpur yang dipakai pada sumur T-3 dan T-2 sudah aman, namun pada sumur T-4 seharusnya tetap di 9,9 ppg dari kedalaman 5082 ft. - 10521 ft. MD. Hasil analisis hipotesis kestabilan sesar didapatkan bahwa rekomendasi area injeksi CCS terletak pada bagian barat Lapangan OJ.
ANALISIS KORELASI MODULUS ELASTISITAS MENGGUNAKAN PARAMETER MEKANIS DAN FISIS UNTUK STABILITAS UNDERGROUND MINING LAPANGAN “SEVERA”.
Mining has seen an increase in production over the past two decades, with mining methods becoming crucial in determining the effectiveness of exploration and mineral reserve production. Underground mining processes using the block caving method support production effectiveness and minimize adverse environmental impacts, but carry high safety risks. Workplace safety is an essential aspect to consider in the mining process. Geomechanical science in conducting mass monitoring and rock quality assessment is an effective method to minimize mining accidents. In principle, this method involves measuring the core that has been drilled to obtain the rock core's compressive strength value. The initial processing stage involves marking the coordinates of core sample collection at the mining site, where each core sample is classified based on lithology, followed by measurements of VpVs and Uniaxial Compressive Strength (UCS). In this study, petrographic analysis was conducted to provide information on the percentage of mineral components and to measure the mechanical and physical elasticity modulus values for each core sample. After the data was obtained, an analysis was conducted to classify the lithology based on the elastic modulus ratio of the core samples. The elastic modulus ratio for exoscarp is 752.21, classified as a high elastic modulus ratio and represents an area with the lowest potential for rock collapse compared to other areas. For limestone, the value is 590.04, classified as a medium to high elastic modulus ratio. For altered limestone, the value is 587.04, classified as a medium to high elastic modulus ratio and is an area with relatively stable rockfall potential. For marble, the value is 590.06, classified as a moderate elastic modulus ratio, and for diorite, the value is 659, classified as a moderate elastic modulus ratio, and is an area with the highest potential for rock collapse compared to other areas
PEMODELAN GEOMEKANIKA UNTUK KESTABILAN LUBANG BOR LAPANGAN BAKUL, CEKUNGAN SUMATRA TENGAH, RIAU
Lapangan Bakul merupakan salah satu lapangan migas yang terletak di Cekungan Sumatra Tengah, Provinsi Riau. Lapangan ini menunjukkan adanya indikasi permasalahan kestabilan lubang bor akibat penggunaan berat lumpur yang cenderung terlalu tinggi, sehingga berisiko menyebabkan kerusakan pada formasi. Oleh karena itu, analisis kestabilan lubang bor dan pemodelan geomekanika diperlukan untuk memahami distribusi tegasan in-situ dan menentukan strategi pengeboran yang optimal. Penelitian ini dilakukan dengan mengestimasi nilai geomekanika menggunakan data log. Estimasi nilai geomekanika yang dilakukan antara lain tegasan vertikal (Sv) dari log densitas, tegasan horizontal minimum (Shmin) dari data leak off test, dan tegasan horizontal maksimum (SHmax) dari observasi kegagalan pada lubang bor. Selain itu, persamaan empiris juga banyak digunakan berdasarkan berbagai data log untuk mengisi nilai geomekanika yang tidak tersedia dan untuk menyusun properti mekanika batuan. Hasil pemodelan digunakan untuk mengevaluasi kestabilan lubang bor serta berat lumpur yang sesuai dengan kondisi bawah permukaan. Hasil pemodelan menunjukkan bahwa Lapangan Bakul berada pada rezim sesar geser (SHmax > SV > Shmin) dengan arah SHmax sebesar N30°E. Gradien nilai geomekanika pada kondisi tekanan normal yaitu SHmax sebesar 1,41 psi/ft, Sv sebesar 0,95 psi/ft, Shmin sebesar 0,82 psi/ft. Zona underpressure teridentifikasi pada Formasi Lakat akibat proses uplift, sementara zona overpressure ditemukan pada Formasi Binio akibat mekanisme loading. Berdasarkan hasil analisis kestabilan lubang bor, disarankan agar berat lumpur disesuaikan secara bertahap mengikuti perubahan kondisi tegasan dan tekanan pori. Arah pengeboran yang ideal untuk meminimalkan risiko ketidakstabilan adalah sejajar dengan arah tegasan horizontal maksimum. Oleh karena itu, perencanaan arah pengeboran dan berat lumpur perlu disesuaikan dengan kondisi tegasan in-situ agar lubang bor tetap stabil selama operasi pemboran.
MODEL GEOMEKANIKA SATU DIMENSI UNTUK KESTABILAN LUBANG BOR LAPANGAN T, CEKUNGAN JAWA BARAT UTARA, JAWA BARAT
Lapangan T, yang dioperasikan oleh Pertamina EP di Cekungan Jawa Barat Utara, memiliki kondisi overpressure yang memengaruhi tegasan in-situ dan kestabilan lubang bor. Penelitian ini bertujuan mengetahui model geomekanika satu dimensi menggunakan data log untuk memahami rezim tegasan in-situ dan analisis kestabilan lubang bor di Lapangan T. Estimasi tegasan vertikal dan tekanan pori dari data log densitas dan sonik. Data log sonik juga dipakai untuk mengestimasi parameter mekanika batuan seperti nisbah Poisson, Modulus Young, dan kuat tekan batuan. Parameter-parameter ini kemudian digunakan untuk mengestimasi tegasan horizontal maksimum dan minimum. Hasil pemodelan geomekanika ini kemudian digunakan sebagai masukan dalam analisis kestabilan lubang bor, mencakup gradien rekah dan orientasi pengeboran, untuk menentukan berat lumpur pemboran yang optimal. Model geomekanika satu dimensi menunjukkan Lapangan T berada pada rezim sesar naik (SHmax > Shmin > Sv) pada interval Formasi Cisubuh dan rezim sesar geser (SHmax > Sv > Shmin) pada interval Formasi Parigi sampai batuan dasar dengan arah SHmax sebesar N15°E. Hasil pemodelan geomekanika satu dimensi menunjukkan Lapangan T memilki satu tren tegasan utama yaitu saat kondisi tekanan hidrostatik. Gradien nilai geomekanika pada kondisi tekanan hidrostatik Lapangan T memiliki rata-rata gradien tekanan pori sebesar 0,43 psi/ft, tegasan vertikal sebesar 1,021 psi/ft, tegasan horizontal minimum sebesar 0,7735 psi/ft, dan tegasan horizontal maksimum sebesar 1,461 psi/ft. Berat lumpur menyesuaikan dengan litologi masing-masing sumur dan rezim tegasan yang berlaku. Berat lumpur rekomendasi dimulai dengan 1.1 SG pada Formasi Cisubuh dan dinaikkan perlahan saat mencapai overpressure pada Formasi Talangakar dan diturunkan kembali pada Formasi Jatibarang sampai batuan dasar. Arah pengeboran yang direkomendasikan yaitu N15ºE untuk rezim sesar naik dan sesar geser dan N105ºE untuk rezim sesar geser – normal dengan inklinasi pengeboran 60º - 90º.
PENILAIAN RISIKO KEGAGALAN BATUAN AKIBAT TEKANAN MENGGUNAKAN SIMULASI GEOMEKANIKA TERPADU 4D PADA PENYIMPANAN CO2 DI AKUIFER SALIN : STUDI KASUS DI LAPANGAN X
The growing global demand for energy and reliance on fossil fuels contribute to emissions, while Earth's temperature rise must be limited to below 1.5°C. Carbon Capture and Storage (CCS) offers a decarbonization strategy for safely storing CO2 underground. However, continuous CO2 injection leads to pressure build-up, inducing geomechanical risks, particularly rock failure due to shear stress. This study assesses rock failure in CO2 storage within a saline aquifer limestone formation, using the Mohr-Coulomb criterion and fracture pressure gradient to evaluate geomechanical risks. It also identifies key factors affecting rock failure and determines the effective storage capacity and percentage of each mechanism. A reservoir simulation of the static model was first conducted to determine a safe injection rate, based on the fracture pressure gradient of 0.7 psi/ft. An injection rate of 20 MMSCFD resulted in a maximum BHP of 2692.966 psi, well below the safety limit of 2732.48 psi (90% of BHP fracture). The base case simulation was then developed using pessimistic parameters to reflect the worst-case scenario. The 4D Coupling Geomechanics Simulation, based on the Mohr-Coulomb criterion (cohesion of 0 and angle of 30°), was performed with 20 years of continuous injection, resulting in rock failure throughout. A second simulation, using a minimum rock cohesion value of 0.1 MPa, showed no rock failure, establishing this new set of parameters as the best estimate for real-world applications. A sensitivity analysis was carried out using a Two-Factorial Design of Experiment (DOE) to assess the influence of key parameters on rock failure. The analysis considered three factors: injection rate, Young's modulus, and Poisson's ratio, with Well Block Pressure (WBP) as the response variable representing rock failure. The results show that the injection rate and Young's modulus are the most significant parameters affecting rock failure. This study emphasizes the importance of using representative geomechanical data, especially since Young's modulus plays a crucial role in rock failure. Based on the best estimate parameters, the effective storage capacity for injecting 20 MMSCFD of supercritical CO? with one injector well over 20 years is 146.1 BSCF, with trapping mechanisms comprising 73.2% structural trapping, 11.5% residual trapping, and 15.3% solubility trapping.
PENENTUAN INTERVAL REKAHAN BERBASIS GEOMEKANIKA PADA RESERVOIR BATUPASIR: STUDI KASUS SUMUR-X, JAWA BARAT
Indonesia continues to rely heavily on oil and natural gas as its primary energy sources, despite a downward production trend caused by aging wells and limited new discoveries. To meet increasing domestic energy demand, hydraulic fracturing has emerged as a key stimulation technique, especially in low-permeability reservoirs. However, the success of fracturing is often uncertain due to geological and geomechanical heterogeneity. This study aims to reduce that uncertainty by evaluating reservoir fracability using brittleness and fracability indices derived from petrophysical and geomechanical log data. A comprehensive methodology was developed, consisting of log interpretation, rock mechanical properties analysis, index calculation, and identification of fracable intervals. The analysis uses well log data from Well-X, located in West Java. Elastic parameters such as Young’s modulus and Poisson’s ratio were derived and calibrated to static conditions to better represent in-situ rock behavior. These were used to calculate the brittleness and fracability indices using a modified Rickman approach. To improve representativeness, local cut-off values were established through statistical analysis, with a brittleness index > 16.3559 and fracability index < 1.4298 found to best reflect the characteristics of soft sandstone formations. The analysis identified three potential zones (Formations P, Q, and R). These intervals are characterized by high brittleness, large Young’s modulus, low Poisson’s ratio, and low ?/? ratios, with formation Q as the primary the target for hydraulic fracturing due to its positive oil indications. This study demonstrates that integrating local petrophysical and geomechanical data improves the reliability of fracability evaluation, ultimately supporting more efficient and targeted stimulation design in similar soft sandstone reservoirs.
ANALISIS POTENSI RESERVOIR BASEMENT FRACTURE: STUDI KASUS POST-DRILLING ANALYSIS SUMUR
Cekungan Sumatra Selatan merupakan salah satu cekungan besar di Indonesia sebagai penghasil minyak dan gas yang didefinisikan sebagai cekungan super karena diperkirakan masih memiliki potensi cadangan setidaknya 5 BBOE. Banyak temuan besar di Cekungan Sumatra Selatan berasal dari reservoir batuandasar yang memiliki rekahan alami. Memahami distribusi rekahan dan hubungannya terhadap rekahan pada reservoir secara ruang dan waktu merupakan hal yang penting untuk menentukan orientasi rekahan utama yang bertindak sebagai permeabilitas primer. Evaluasi geomekanika yang mencangkup analisis rekahan kritis dapat digunakan untuk mendapatkan pemahaman tersebut khususnya pada Sturktur PPP yang diketahui tidak dapat mengalirkan hidrokarbon pada objektif reservoir batuandasar. Diketahui struktur PPP-1 dikelilingi oleh sumur yang telah terbukti dapat mengalirkan hidrokarbon di batuandasar sehingga masih menjadi teka-teki mengapa struktur ini tidak dapat ditemukan akumulasi hidrokarbon. Analisis Geomekanika pada beberapa sumur sekitar yaitu PPP-1, Bungin-1, Bungin-2, dan Rayun-2. Metode yang digunakan dalam penelitian adalah analisis geomekanik 1D dan analisis log gambar. Metode – metode tersebut digunakan untuk menentukan karakteristik rekahan kritis beserta distribusinya, sejarah pembentukan rekahan dan tegangan yang membentuknya. Asumsi yang digunakan adalah rekahan yang ditemukan di batuandasar tidak terpengaruh proses diagenesis intensif yang mengubah properti batuan dan hasil perhitungan stress secara dinamik memiliki hasil yang valid dengan nilai mendekati nilai originalnya. Hasil pemetaan bawah permukaan menunjukkan daerah penelitian didominasi oleh tren struktur berarah baratlaut – tenggara dan timurlaut – baratdaya pada interval batuandasar. Tren struktur yang timurlaut – baratdaya didominasi oleh sesar normal sedangkan struktur yang berarah Barat Laut – Tenggara terdiri atas sesar naik. Arah dari SHmax di Sumur PPP-1, tersebut yaitu timurlaut – baratdaya yang searah dengan arah rekahan tarik. Hasil evaluasi arah tegangan utama pada struktur sekitar dan referensi menunjukkan arah tegasas lokal pada struktur PPP menunjukkan hasil orientasi yang serupa yaitu berarah timur laut – baratdaya. Hasil pemodelan geomekanika yang dilakukan di Sumur PPP, menunjukkan bahwa rezim tektonik di area penelitian adalah rezim strike-slip, dengan arah tegangan utama adalah timurlaut – baratdaya. Perbandingan gradien nilai tegangan in-situ yang menunjukkan besarnya nilai tegangan-tegangan dapat digunakan untuk menganalisis rezim sesar yang aktif. Daerah penelitian memiliki rezim sesar yang memengaruhi wilayah ini, yaitu sesar geser (strike-slip) dicirikan dengan perbandingan SHmax > Sv > SHmin. Dari hasil evaluasi geomekanika juga menunjukkan potensi Formasi Talangakar menjadi batuan tudung berindikasi positif terlihat dari kondisi overpressure. Hasil evaluasi Rekahan kritis dievaluasi dengan menggunakan beberapa koefisien kritis dan menunjukkan ada potensi tidak terdapatnya rekahan kritis dan terdapatnya rekahan kritis. Orientasi rekahan kritis di tunjukan dengan orientasi mayor memiliki arah N 105 – 115°E sedangkan orientasi minor memiliki arah N 45 – 50°E. Hasil analisis sistem petroleum menunjukkan potensi kegagalan akumulasi yang terjadi di Struktur PPP tidak dikarenakan oleh bentukan cebakan, kondisi reservoir, dan batuan tudung. Evaluasi analisis batuan induk menunjukkan potensi adanya charging hidrokarbon cukup baik di area Struktur PPP, namun terdapat potensi tidak baiknya waktu pengisian akumulasi sehingga tidak diperoleh akumulasi di struktur PPP.
OPTIMIZED HYDRAULIC FRACTURE DESIGN USING A PREDICTIVE SIMULATED APPROACH: A CASE STUDY OF “X-3” WELL
Hydraulic fracturing is one of the effective methods of well stimulation that is widely used to enhance hydrocarbon production for wells experiencing a decline in production and having unconventional potential reserves that is unattainable through other stimulation methods. The purpose of a hydraulic treatment is to increase the productivity of a well. “X-3” oil well, located in Field “X” which is a mature oil field, is a candidate for hydraulic fracturing treatment due to its low productivity and reserves within a tight sand reservoir in TAF-1 formation which consists of low permeability shale-sand layers. This study aims to create a relevant interpretation of the targeted formation through geomechanics interpretation and design an optimum hydraulic fracture treatment based on the formation model. Geomechanics interpretation is conducted by analyzing a set well logging data to calculate elastic properties which is an important parameter of rock mechanics. Empirical approaches are used to create a permeability prediction model due to lack of data from core sample. The selection of fracturing fluid and proppant is based on existing guidelines that is adjusted to the case. The design of fracture geometry and treatment is based on the calculation of Unified Fracture Design which is set as an ideal reference for optimum geometry. A simulated approach using commercial fracturing software is conducted to generate a near-actual fracture model based on the calculated optimum geometry. The resulting accepted fracture geometry is analyzed to identify the increase of productivity through Folds of Increase determination and a 1-year production forecast.
OPTIMIZED HYDRAULIC FRACTURE DESIGN USING A PREDICTIVE SIMULATED APPROACH: A CASE STUDY OF “X-3” WELL
Hydraulic fracturing is one of the effective methods of well stimulation that is widely used to enhance hydrocarbon production for wells experiencing a decline in production and having unconventional potential reserves that is unattainable through other stimulation methods. The purpose of a hydraulic treatment is to increase the productivity of a well. “X-3” oil well, located in Field “X” which is a mature oil field, is a candidate for hydraulic fracturing treatment due to its low productivity and reserves within a tight sand reservoir in TAF-1 formation which consists of low permeability shale-sand layers. This study aims to create a relevant interpretation of the targeted formation through geomechanics interpretation and design an optimum hydraulic fracture treatment based on the formation model. Geomechanics interpretation is conducted by analyzing a set well logging data to calculate elastic properties which is an important parameter of rock mechanics. Empirical approaches are used to create a permeability prediction model due to lack of data from core sample. The selection of fracturing fluid and proppant is based on existing guidelines that is adjusted to the case. The design of fracture geometry and treatment is based on the calculation of Unified Fracture Design which is set as an ideal reference for optimum geometry. A simulated approach using commercial fracturing software is conducted to generate a near-actual fracture model based on the calculated optimum geometry. The resulting accepted fracture geometry is analyzed to identify the increase of productivity through Folds of Increase determination and a 1-year production forecast.
OPTIMIZED HYDRAULIC FRACTURE DESIGN USING A PREDICTIVE SIMULATED APPROACH: A CASE STUDY OF “X-3” WELL
Hydraulic fracturing is one of the effective methods of well stimulation that is widely used to enhance hydrocarbon production for wells experiencing a decline in production and having unconventional potential reserves that is unattainable through other stimulation methods. The purpose of a hydraulic treatment is to increase the productivity of a well. “X-3” oil well, located in Field “X” which is a mature oil field, is a candidate for hydraulic fracturing treatment due to its low productivity and reserves within a tight sand reservoir in TAF-1 formation which consists of low permeability shale-sand layers. This study aims to create a relevant interpretation of the targeted formation through geomechanics interpretation and design an optimum hydraulic fracture treatment based on the formation model. Geomechanics interpretation is conducted by analyzing a set well logging data to calculate elastic properties which is an important parameter of rock mechanics. Empirical approaches are used to create a permeability prediction model due to lack of data from core sample. The selection of fracturing fluid and proppant is based on existing guidelines that is adjusted to the case. The design of fracture geometry and treatment is based on the calculation of Unified Fracture Design which is set as an ideal reference for optimum geometry. A simulated approach using commercial fracturing software is conducted to generate a near-actual fracture model based on the calculated optimum geometry. The resulting accepted fracture geometry is analyzed to identify the increase of productivity through Folds of Increase determination and a 1-year production forecast.
OPTIMIZED HYDRAULIC FRACTURE DESIGN USING A PREDICTIVE SIMULATED APPROACH: A CASE STUDY OF “X-3” WELL
Hydraulic fracturing is one of the effective methods of well stimulation that is widely used to enhance hydrocarbon production for wells experiencing a decline in production and having unconventional potential reserves that is unattainable through other stimulation methods. The purpose of a hydraulic treatment is to increase the productivity of a well. “X-3” oil well, located in Field “X” which is a mature oil field, is a candidate for hydraulic fracturing treatment due to its low productivity and reserves within a tight sand reservoir in TAF-1 formation which consists of low permeability shale-sand layers. This study aims to create a relevant interpretation of the targeted formation through geomechanics interpretation and design an optimum hydraulic fracture treatment based on the formation model. Geomechanics interpretation is conducted by analyzing a set well logging data to calculate elastic properties which is an important parameter of rock mechanics. Empirical approaches are used to create a permeability prediction model due to lack of data from core sample. The selection of fracturing fluid and proppant is based on existing guidelines that is adjusted to the case. The design of fracture geometry and treatment is based on the calculation of Unified Fracture Design which is set as an ideal reference for optimum geometry. A simulated approach using commercial fracturing software is conducted to generate a near-actual fracture model based on the calculated optimum geometry. The resulting accepted fracture geometry is analyzed to identify the increase of productivity through Folds of Increase determination and a 1-year production forecast.
OPTIMIZING WELL SELECTION CANDIDATE AND HYDRAULIC FRACTURING TREATMENT IN SOFT ROCK AND HARD ROCK FORMATION: CASE STUDIES IN FIELDS X AND Y.
Currently, 66.67% of the global daily oil production and 90% of Indonesia's oil production are derived from mature fields, whose capacity has gradually declined. Governments, oil corporations, and service providers must devise strategies to effectively address society's energy needs in daily life and ensure the business's financial stability. Hydraulic fracturing has proven to be a cost-efficient method for improving productivity in mature oil fields. Nevertheless, these operations require substantial financial resources, including engaging in high-risk activities and dealing with uncertainty. This study aims to thoroughly examine the process of identifying appropriate candidates for hydraulic fracturing operations by focusing on rock mechanics analysis, enhancing the efficiency of hydraulic fracturing operations, and evaluating post-job analysis to find which well gives the highest investment return after the operations are performed. A geomechanics analysis is first conducted as a screening parameter for well-candidate selection. The analysis results include Poisson's ratio, Young's modulus, and Minimum horizontal stress, giving us information about the in-situ stress condition at the zone of interest, which we can predict where and how the fracture goes. Subsequently, by utilizing the Stimplan-NSI simulator, we may better understand the hydraulic fracture formed concerning the specific characteristics of the reservoir and the rock formation. Finally, after adjusting specific treatment parameters to reach the desired outcome for both hard rock and soft rock formations, nodal analysis is conducted to identify the most optimal candidate for fracturing operations. Ultimately, a highly effective ranking system for potential candidates is achieved with various recommendations, such as conducting a study or test before main-frac operations, setting clear objectives for fracturing design in both soft and hard rock formations, and optimal treatment involves controlling the injection rate, proppant mass, pad volume, and gel loading of fracturing fluids within the desired range. The project's profitability is likely to grow, and uncertainties are projected to decrease by selecting a promising candidate and implementing an optimal treatment strategy.