📚 Eksplorasi & Komparasi Topik Dokumen
Pencarian topik
Hasil Dokumen
Ditemukan: 14 dokumenDIAGNOSTIK PRAKTIS PERMASALAHAN PRODUKSI AIR MENGGUNAKAN ANALISIS WATER CUT DAN WOR DERIVATIVE PADA LAPANGAN AX
The AX Field is one of the largest onshore oil fields in Indonesia and contributes significantly to the country’s oil production. After reaching peak production of approximately higher than 220 MBOPD, the field has entered a mature production stage characterized by declining oil rates and increasing water production rapidly. The main producing reservoir is the heterogeneous carbonate buildup of the Kujung Formation that can create preferential flow paths and lead to uneven fluid displacement. This study aims to analyze declining production and rapidly increase of water production in the AX Field through an integrated evaluation of field performance and well-level diagnostics for maintenance field production performance in the future. The study workflow begins with the collection and validation of production and injection data based on production history data from August 2009-May 2025, followed by the development of a historical field production performance plot to evaluate reservoir behavior over time, complemented by the construction of a combined Voidage Replacement Ratio (VRR) and reservoir pressure versus time plot to assess reservoir drive mechanisms and pressure support. Then, production historical evaluation is conducted using Decline Curve Analysis (DCA) to determine decline rate (Di) field and wells. Based on these evaluations, a problematic well is identified for further detailed analysis based on wells production history data. Water production behavior is then examined for every well in the field using DCA method, fractional method, and Watercut/Life time method. Further diagnostic analyses include Chan plot evaluation for production wells, Hall plot interpretation for injection wells, and assessment of well completion data alongside oil–water contact (OWC) conditions. The integration of these analyses provides the basis for proposing appropriate mitigation strategies to optimize production performance and manage excessive water production. The results indicate that injection pressure support successfully stabilized reservoir pressure after the early depletion stage. However, diagnostic analysis shows that channeling is the dominant mechanism causing water breakthrough in several wells, with some wells also exhibiting bottom-water coning. Fractional flow analysis estimates a theoretical breakthrough watercut of approximately 85.7%, and comparison with field data suggests that several wells experienced earlier breakthrough due to preferential flow through high-permeability pathways. The integrated analysis provides insights for identifying problematic wells and supports the implementation of targeted water-management strategies to improve sweep efficiency and sustain oil recovery in the AX Field.
PEMETAAN KEMAMPUAN LAJU ALIRAN PRODUKSI PADA JARINGAN PIPA UNTUK SENSITIVITAS UKURAN PIPA: STUDI KASUS LAPANGAN X
Heavy oil Field X in Jambi, that was produced in 2004, has experienced production losses ranging from 6 to 63 BFPD along its pipeline. Production facilities consist of 4-in flowline connecting 17 wells to the three PAD manifolds, which are subsequently routed through an 8-in trunkline to the central facility.,The internal pipeline network of Field X has not undergone cleaning for over two decades. Paraffin wax deposition and pipeline degradation are predicted to be the primary issues. Production data on 10th of June 2025, with a flow loss of 9.17 BFPD, were used to evaluate the operational performance of the pipeline network by assessing the wellhead pressure capacity using PipeSIM software. Technical assumptions include an internal diameter reduction of the 8-inch trunkline by 3.75” at PAD-5 and 2.25” at PAD-1 & PAD-7, 1” reduction in 4-inch flowlines, and extreme holdup factor. The matching results indicated friction factors for PAD-1, PAD-7, and PAD-5 of 1.55, 13.5, and 15.4, respectively. Suggesting severe internal pipeline problems and implying that the actual deposition may be greater than the assumed values. The analysis identified several 4-inch flowlines with substantial accumulation, particularly from wells M–10, M–31, and M–45 (PAD–1), M–47 (PAD-5), as well as M–08 (PAD–7). A pipe size sensitivity analysis predicted that the installed 8-inch trunkline resulted in the smallest production loss (8.23 BFPD) compared to the 6-inch (8.49 BFPD) and 4-inch (11.22 BFPD) trunklines. Therefore, the 8-inch trunkline is recommended to remain in use, provided that internal cleaning of the pipleine is carried out.
SEEKING THE INFLUENCING PARAMETERS ON CO2-EOR PROJECTS THROUGH SENSITIVITY ANALYSIS USING DESIGN OF EXPERIMENT
With many of Indonesia's oil fields reaching a mature stage, Enhanced Oil Recovery (EOR) methods are critical for maximizing national hydrocarbon production. This study evaluates the potential of CO? injection in three distinct Indonesian oil fields: Field X (carbonate), Field Y (sandstone-fluvial), and Field Z (sandstone-deltaic) using the CO?PM predictive model within the EORgui software. The research aims to identify the most influential reservoir and production parameters on recovery, compare performance across different geological settings, and develop a statistical model to quantify these relationships. A Two-Level Full Factorial Design of Experiments (DoE) was conducted for each field, and the results were analyzed using Pareto Charts and residual analysis. The findings consistently show that volumetric parameters specifically Pattern Area, Porosity, and Thickness with their interactions are the most statistically significant factors controlling cumulative oil production (Np), regardless of the depositional environment. While the DoE was successful in screening and ranking these key drivers, the resulting linear regression models exhibited non-normal residuals and non-constant variance, indicating that a more advanced model, such as one developed through Response Surface Methodology (RSM), is required for precise quantitative prediction.
PENGENALAN WELL COMPLEXITY INDEX (WCI) UNTUK MEMPREDIKSI ESTIMATED ULTIMATE RECOVERY PADA SKALA SUMUR: STUDI KASUS DI LAPANGAN TUA X
This study, conducted on Well X located in Duri Formation, aims to assess and predict the oil that will be recovered by this well using the Well Complexity Index (WCI), which is modified from Reservoir Complexity Index (RCI), as the primary indicator. WCI is calculated for multiple wells and multiple sand layers using a weighted scoring system based on percentile classifications of each parameter. The cumulative oil production is represented by the Estimated Ultimate Recovery (EUR), obtained from production history decline curve analysis in OFM software, which accounts for both historical production and projected future output. The relationship between WCI and EUR is analyzed using graphical interpretation and regression techniques. An initial analysis on almost all wells showed a weak negative correlation between WCI and EUR with R² = 0.3137, but with a clear decreasing trend. A more focused analysis was then performed on wells with high cumulative oil production, indicates that these wells had already recovered most of their oil. The order of impact on the complexity index from greatest to lowest is permeability, net pay thickness, start production year, sand thickness, porosity, and lastly, water saturation. The 0.035% error rate in the differences between the actual and calculated cumulative oil production might serve as supporting evidence of the influencing parameters that influence oil production. The findings demonstrate that WCI can be used not only as a classification tool but also as a proxy for estimating recovery potential at the well level, particularly in early development stages or data-scarce environments without reservoir modeling and simulation.
OPTIMASI HYDRAULIC FRACTURING UNTUK PENINGKATAN PRODUKSI LAPANGAN TUA: STUDI KASUS SUMUR TM-06 DAN TM-14
Production decline in mature oil fields poses a major challenge in meeting national energy demands. One of the most effective solutions for enhancing production in mature fields is hydraulic fracturing, which improves fluid flow by creating artificial fractures within the formation. However, given the high operational costs, it is essential to develop an optimized fracture design and strategy to ensure that hydraulic fracturing is both technically effective and economically feasible. This study aims to optimize hydraulic fracturing design for wells TM-06 and TM-14 in Field Z, Jambi Province, through appropriate selection of fracture models, geometry design, and proppant and fracturing fluid types suited to the reservoir characteristics. Candidate wells were selected based on Heterogeneity Index (HI) analysis and Estimated Ultimate Recovery (EUR) calculations using reciprocal and decline curve analysis (DCA) methods. Fracture design was conducted using the KGD model, with fracture half-length (Xf) sensitivity analysis performed using equations by Baker, Economides (2013), Montgomery (2015), and graphical approaches. The design results demonstrated a significant increase in production rates after stimulation: for TM-06, the maximum total liquid rate increased from 235.97 STB/day to 819.25 STB/day, while for TM-14, it increased from 304.38 STB/day to 1,146.68 STB/day. Hydraulic fracturing also successfully reduced skin values and improved Absolute Open Flow (AOF). From an economic perspective, Brady Sand was found to be the most cost-effective proppant option, reducing proppant costs by more than 90% compared to resin-coated sand, while maintaining optimal fracture performance. This study demonstrates that data-driven hydraulic fracturing design and optimization can significantly enhance production in mature fields and can serve as a reference for other fields with similar geological conditions
EVALUASI PETROFISIKA DAN PENGEBORAN KOMPREHENSIF PADA RESERVOAR BERKUALITAS RENDAH (LQR) MENGGUNAKAN TEKNOLOGI LWD: STUDI KASUS RESERVOAR B4 DI LAPANGAN Y
Field Y is one of the fields located at S Basin. This field was produced since 1954 and currently has declined. It’s important to note that low quality reservoir (LQR) can be exploited more using LWD technology especially horizontal well. Field Y contains some reservoirs in multilayer settings, one of them is reservoir B4. In this study reservoir B4 would be evaluated for understanding the petrophysical characteristics especially potential net pay, porosity, permeability, and resistivity as mains parameters to examine reservoir quality. The workflows process was done by conducted petrophysical analysis, including shale volume calculations, porosity calculations, water saturation using Indonesia and Simandoux equations, cut off determination, then net pay estimation. Some descriptive statistics also be conducted to help us understand data distribution. The results show that there is low quality reservoir (LQR) with 14.5 – 16 ft net pay from analysis of offset well. The reservoir B4 is characterized by petrophysical parameters, average shale volume around 0.36, average porosity 0.19, average deep phase resistivity around 8.62 ohmm, average attenuation deep resistivity around 7.03 ohmm and permeability estimation 66.283 mD in average, which are from horizontal well. The horizontal was deployed by ADR geosteering tools for precise well placement with final trajectory is approximately 9-10 ft below the sand layer of top B4.
STUDI TENTANG PENGARUH ION SULFAT DALAM KOMPOSISI AIR GARAM TERHADAP KINERJA SURFAKTAN ANIONIK-LINIER DALAM PENINGKATAN PEROLEHAN MINYAK DI LAPANGAN X
The global oil demand is increasing due to economic integration, encouraging petroleum engineers to focus on recovering hydrocarbons and expanding production. A strategic plan for recovering oil is needed, including primary, secondary, and tertiary recovery methods, with chemical EOR being the most promising method. The study focuses on sulfate concentrations, salinity, and flow rate changes, assessing oil recovery factors on surfactant performance. The author developed a comprehensive methodology for investigating surfactant flooding, focusing on sulfate ions impact on brine composition and optimal injection production rate. The methodology includes a literature review, laboratory study, and reservoir simulation using CMG STARS 2021. The recovery factor in Field X increases with injection/production rate ratios, with optimal ratios between 1.0 and 1.5. Low-salinity surfactant alters rock wettability, resulting in water saturation shifts from 44% to 62%. Surfactant injection leads to greater oil recovery than waterflooding. The calculation shows that a 100 bbl/day injection rate at waterflood can achieve a maximum cumulative oil volume of 551,237 bbl in Field X. A modification of the valence charge of the anion does not affect the interfacial tension (IFT) in the case of Na?SO?. Surfactant injection reduces water cut and oil saturation, increasing cumulative oil volume. The maximum recovery factor achieved through surfactant injection was 35.04% of OOIP and following water flooding.
ADVANCED METHOD FOR OPTIMIZING OIL PRODUCTION: NONLINEAR AND LINEAR OPTIMIZATION COMBINATION WITH BINARY INTEGER PROGRAMMING FOR ARTIFICIAL LIFT APPLICATION AT X FIELD
Mature fields require artificial lift methods to enhance production. As production declines and watercut increases, wells are often converted from gas lift to ESPs, as ESPs are an attractive alternative for achieving lower bottom hole pressure. This situation is critical when deciding on artificial lift conversion. In this study, gas lift wells will be converted to ESP systems under specific conditions to achieve maximal production. Binary Integer Programming (BIP), alongside nonlinear and linear programming, will be used to facilitate this objective, ensuring enhanced production within existing limitations. Seven wells will be evaluated to determine whether to convert to ESPs or remain in the gas lift system. An inflow performance analysis will assess the potential production increment for each well. Optimizing the existing gas lift system is necessary to ensure that the current system is performing optimally. Nonlinear optimization using Sequential Quadratic Programming (SQP) will be conducted for lift gas allocation optimization. The availability of 3.5 MMSCFD of gas injection serves as a constraint for nonlinear optimization. Additionally, linear programming will be applied for design rate optimization in each well, constrained by surface facility capacity of 9,000 BLPD. Both nonlinear and linear programming prove effective for lift gas allocation and design rate optimization, respectively. The methods result in an increase in total oil production by up to 318.26 BOPD for lift gas allocation optimization and 534.88 BOPD for design rate optimization. Each method respects the constraints, with the total gas injection required being 3.5 MMSCFD and the total liquid production capped at 9,000 BLPD. These results are used to guide artificial lift substitution decisions using BIP. BIP is employed to achieve maximal oil production, constrained by surface facility capacity of 9,000 BLPD and a special condition that a well will only be converted to ESPs if the incremental oil production from design rate optimization exceeds 15 BOPD. This threshold is set to cover the costs of well service, electricity, and pump rental. BIP results indicate that three wells—B-X04, B-X07, and B-X08—will be converted to ESPs, leading to a total oil production increase of up to 490.25 BOPD. BIP proves to be a powerful tool for decision-making, helping to achieve maximal oil production within multiple constraints and conditions.
INTEGRASI ANALISIS BAWAH PERMUKAAN UNTUK IDENTIFIKASI KOMPARTEMEN RESERVOIR DI LAPANGAN GTN, CEKUNGAN SUMATRA TENGAH
Lapangan GTN yang sudah berproduksi sejak Tahun 1990 dari tiga reservoir (D840, D900, dan BK1000A) awalnya diinterpretasikan hanya memiliki satu kompartemen reservoir untuk setiap lapisan produksi, meskipun indikasi dari data tekanan reservoir dan pola log resistivitas serta saturasi menunjukkan hal yang berbeda. Penelitian tesis dilakukan dengan melakukan interpretasi yang lebih detail meliputi; hubungan pola struktur geologi (sesar, lipatan) hasil sejarah tektonik pada area penelitian, perhitungan kemampuan sesar dalam menahan kolom hidrokarbon yang direpresentasikan oleh nilai SGR (Shale Gauge Ratio), korelasi elektrofasies dan identifikasi unit reservoir secara horizontal, analisis tekanan reservoir, perbandingan lebar dan tebal fasies, penentuan kedalaman kontak fluida dengan mempertimbangkan waktu relatif produksi minyak, serta analisis geokimia (oil fingerprinting). Hasil penelitian tesis mendapatkan hasil bahwa setiap lapisan produksi minyak terbagi menjadi beberapa kompartemen reservoir horizontal. Hasil analisis kompartemen reservoir berupa Reservoir D840 terdiri dari enam kompartemen, Reservoir D900 terdiri dari lima kompartemen, dan Reservoir BK1000A terdiri dari lima kompartemen. Batas kompartemen reservoir horizontal dinterpretasikan lebih dominan dibatasi oleh variasi atau perubahan nilai porositas (porositas efektif atau PHIE dengan cut off VSH <0,8 dan cut off PHIE >0,15). Keterbatasan kualitas data seismik 2D yang digunakan untuk identifikasi sesar-sesar minor menyebabkan kesulitan untuk melihat fault throw yang jelas, hal ini selanjutnya berkorelasi dengan tingkat keakuratan hasil analisis potensi awal sekatan sesar (fault seal analysis). Variasi nilai porositas mencerminkan heterogenitas internal dalam tubuh fasies selama proses sedimentasi dan mencerminkan storage unit atau unit resevoir. Perhitungan volumetrik atau sumber daya minyak bumi (Original Oil in-Place, OOIP) hasil penelitian mereduksi nilai OOIP hasil studi sebelumnya. Hasil perhitungan sumber daya minyak bumi yang baru selanjutnya divalidasi ke hasil analisis material balance, kemudian hasil cadangan sisa minyak bumi juga divalidasi terhadap hasil DCA (decline curve analysis). Nilai cadangan sisa minyak bumi konsisten menunjukkan bahwa potensi terbesar ada di Reservoir D840 dan sangat minim di Reservoir D900 dan BK1000A. Kondisi ini berakibat perubahan fokus skenario pengembangan lapangan lanjutan menjadi lebih utama ke target di Reservoir D840.
ANALYSIS OF SLIDING SLEEVE DOORS LEAKAGE AND THE IMPACT OF GAS LIFT INSTALLATION ON OIL PRODUCTION: A CASE STUDY OF WELL B-1
This study addresses the challenge of declining oil production in well B-1, located in the "Y" Field offshore Java, Indonesia, primarily caused by leakage in the Sliding Sleeve Doors (SSD) and wax deposition. The objective is to analyze the impact of SSD leakage and gas lift installation on well productivity and flow assurance. A comprehensive methodology was used, starting with a literature review to understand the theoretical foundations, followed by data collection from well tests and modeling using a dynamic transient simulator. Sensitivity analysis was conducted on the Productivity Index (PI), leak diameter, and gas injection rate. Key findings indicate that SSD leakage results in significant fluid production through the annulus, initially dominated by gas and subsequently by liquid. The installation of a gas lift significantly increased the production rate from 1500 BOPD to 2200 BOPD. The study reveals that higher PI values and larger leak diameters correlate with increased flow rates and fluid volumes. Additionally, gas lift helps reduce wax formation at the leakage point. The results of this study emphasize the importance of integrating gas lift technology to enhance production efficiency and mitigate issues related to SSD leakage and wax deposition.
THE EFFECTS OF ACETONE SOLVENT ON CO? TRAPPING DISTRIBUTION DURING CO?-ACETONE INJECTION: OPTIMIZATION FOR OIL RECOVERY AND CO? SEQUESTRATION USING WATER-ALTERNATING-GAS IN “B” STRUCTURE AT “S” FIELD
Indonesia's oil production has been declining yearly, while consumption remains high, posing a significant challenge to the country's energy needs. According to the press release by the Ministry of Energy and Mineral Resources (ESDM) in January 2024, national oil and condensate production reached 605.5 thousand barrels of oil per day (bopd) in 2023, a 1.2% decrease compared to 612.7, while CO? emissions have risen by 15% from 2017 to 2021, exacerbating climate change concerns. Carbon Capture, Utilization, and Storage (CCUS) technology, particularly CO?-enhanced oil recovery (EOR), offers a dual solution by increasing oil recovery and reducing greenhouse gas emissions. Implementing CCUS and EOR aligns with Indonesia's goal of achieving net-zero emissions by 2060. On a global scale, the International Energy Agency (IEA) reports a 1.1% increase in CO? emissions from 2022 to 2023, underscoring the urgent need to address climate change as mandated by the Paris Agreement. For this simulation, the dynamic reservoir model was developed using CMG GEMTM Builder Software to identify the effect of operational parameters and propose the most optimum scenario for the "B" Structure and "S" Field reservoir. The sensitivity and comparison study involves forecasting production and trapping mechanism scenarios over 15 years, starting on January 1, 2021. The study evaluates the impact of Acetone solvent on the CO?-Acetone trapping mechanism, building on previous research that primarily examined Acetone's effects on reducing minimum miscibility pressure and enhancing recovery factor. As observed in previous studies, the injection composition of 89% CO? and 11% Acetone is determined based on its ability to optimize miscibility pressure reduction. Results highlight how the Land coefficient and rock type wettability influence CO? trapping mechanisms, comparing continuous CO?-Acetone injection with Water Alternating Gas (WAG) CO?-Acetone injection. The study optimizes the WAG ratio at 0.5 for the "S" Field, demonstrating Acetone's significant impact on residual and solubility trapping during the EOR process, with initial strong performance in residual trapping. However, the residual trapping for the case of adding acetone after the EOR process decreases compared to residual trapping due to pure CO? injection. This occurs because acetone is better at dissolved, especially in oil. This also affects solubility trapping, which is not very significant in the case of acetone addition. Nevertheless, structural trapping with the injection case mixed with acetone shows the best performance in all phases. Overall, CO? storage efficiency with CO?+Acetone injection outperforms pure CO? injection. Analysis across various wettability ranges indicated a minimal Land coefficient impact on CO? storage in reservoirs, with consistent trapping efficiencies across different rock types. Over a 30-year monitoring period, simulations using a single Land coefficient revealed structural trapping at 49.61%, residual trapping at 5.92%, and solubility trapping at 44.47%. In contrast, with Land coefficient variations, structural trapping was 49.63%, residual trapping was 5.80%, and solubility trapping was 44.57%. Although residual trapping decreased by only 0.12% with the variations, it underscored the influence of rock-type wettability on reservoir trapping mechanisms. Further development involves evaluating WAG and Continuous Gas Injection parameters, including cycle numbers, WAG ratios, and gas slug sizes, optimizing for co-optimized oil recovery and storage efficiency. Results indicate a 1.8% increase in oil recovery factor with WAG compared to continuous injection. WAG CO?+Acetone injection shows substantial improvements over continuous injection, with final trapping mechanism distributions showing structural trapping at 46.83%, residual trapping at 7.40%, and solubility trapping at 45.78% after 30 years, compared to continuous injection at 49.61% structural trapping, 5.92% residual trapping, and 44.47% solubility trapping. This underscores the efficacy of WAG injection in enhancing CO? trapping mechanisms in reservoirs.
NORNE FIELD’S E-SEGMENT RESERVOIR SIMULATION TO INVESTIGATE THE ENHANCED OIL RECOVERY POTENTIAL USING POLYMER FLOODING WITH CMG-STARS
The increasing significance of enhanced oil recovery (EOR) from mature fields is driven by the world's growing energy demand and the depletion of existing reserves. Chemical EOR, particularly polymer flooding, may require fewer resources to implement than other EOR techniques, as most oil fields have already initiated waterflooding for secondary recovery. Polymer flooding has shown promising results in recovering viscous oils and enhancing offshore field operations. Given its mature state, the E-Segment of the Norne Field is a suitable candidate for tertiary recovery using polymer flooding. The objective of this thesis is to investigate the effects of polymer flooding on oil recovery through reservoir simulation, focusing on two key sensitivities: injection rate and injected pore volume (PV), accompanied by an economic analysis. Encouraged by the promising findings of polymer flooding, this study simulates different scenarios to assess their impact. Five different cases were investigated in this study. The results indicate that polymer flooding can increase oil recovery by up to 8%. Furthermore, the economic analysis suggests that polymer flooding in the Norne Field’s E-Segment is a cost-effective and feasible option for field development.
COMPREHENSIVE ANALYSIS AND OPTIMIZATION OF HYDRAULIC FRACTURING IN THE TELISA FORMATION, WELL 'X', FIELD 'Y', SUMATRA
This study aims to optimize the hydraulic fracturing design in the Telisa Formation, Y Field, Sumatra, through comprehensive simulation and economic assessment. The primary focus is to enhance oil well productivity by conducting sensitivity analyses on key parameters such as fracturing fluid type, proppant composition, and pump rates. Advanced simulation techniques using specialized software are employed to model various fracturing scenarios, followed by nodal analysis to identify optimal operating conditions. The study evaluates different fracturing fluids, including YF120HTD, YF160HTD, and Clear Fract Fluid, as well as various proppant types, Carbolite, Brady, and RCS. Among these analysis, YF160HTD at a pump rate of 16 bpm was found to be the most effective, achieving a propped fracture half-length of 197.2 feet, a propped width of 0.113 inches, and an effective Fracture Conductivity (FCD) of 1.7. The results demonstrate significant improvements in Fold of Increase (FOI) which value 1.95 and effective fracture geometry, indicating that optimized fracturing designs can lead to more efficient and productive oil extraction processes. The economic analysis reveals that this scenario yields the highest Net Present Value (NPV) of $0.1239 and an Internal Rate of Return (IRR) of 46.51%. This methodology integrates technical and economic considerations to provide a holistic approach to hydraulic fracturing optimization in Telisa formation, Y Field.
OPTIMASI PRODUKSI PADA MATURE FIELD: SCREENING KANDIDAT SUMUR UNTUK STIMULASI HYDRAULIC FRACTURING
Saat ini produksi minyak di Indonesia terus mengalami penurunan karena banyak lapangan yang telah melewati puncak produksinya sehingga banyak sumur yang telah idle atau laju alirnya kecil. Dalam kondisi ini, diperlukan upaya untuk meningkatkan produksi minyak guna memenuhi kebutuhan energi nasional. Upaya tersebut adalah stimulasi sumur, salah satunya menggunakan hydraulic fracturing. Namun, diperlukan seleksi untuk memilih kandidat sumur yang dapat distimulasi karena biaya operasi yang tinggi untuk memaksimalkan produksi. Studi dilakukan pada lapangan Y yang merupakan lapangan minyak dengan formasi sandstone dengan jumlah sumur sebanyak 30 sumur produksi dan injeksi. Pemilihan kandidat sumur dillakukan menggunakan metode heterogeneity index menggunakan data produksi, penentuan recoverable reserve dengan decline curve analysis dan cum-cum plot, identifikasi data sumuran seperti permeabilitas dan skin, dan analisis evaluasi performa sumur menggunakan IPR Pudjo Sukarno (1986). Dari total 30 sumur, didapatkan 2 kandidat sumur untuk stimuasi hydraulic fracturing. Sumur yang kandidat stimulasi adalah TM-20 dan TM-25. Stimulasi hydraulic fracturing dilakukan pada kedua sumur tersebut dengan menggunakan model geometri rekahan PKN dan KGD. Model geometri KGD menunjukkan peningkatan laju alir yang paling tinggi dengan panjang rekahan untuk TM-20 adalah 200 ft, tinggi rekahan 42 ft, dan lebar rekahan 0.205 in., sedangkan untuk TM-25 panjang rekahan yang didapat adalah 250 ft, tinggi rekahan 34 ft, dan lebar rekahan 0.242 in. Dengan model geometri ini, didapat AOF minyak pada TM-20 sebesar 63.7 STB/day dan TM-25 adalah 264.1 STB/day. Studi yang dilakukan menunjukkan bahwa screening dan optimasi yang dilakukan dapat meningkatkan produksi sumur di lapangan tua.