Technical and Economical Study on Increasing Oil Production in Old Wells (Traditional) by Performing Well Maintenance in the CP Field

The CP field is an brown field with a production potential of 2,185 BOPD. However, the realization of CP Field production in the first semester was 1,931 BOPD (88.4% of the production target). From Low & Off data for the period from January to September 2020, it was found that the biggest problem contributing to LPO (Lost Production Opportunity) was caused by artificial lift wells and reduced production from old (traditional) wells.Several solutions can be done in order to solve the problem. Among them is by carrying out well maintenance, both those experiencing a decline in production or wells that have the potential to be activated. By implementing this, it is hoped that it will be able to maintain stability and even increase oil production and distribution through the old (traditional) well. The screening of reactivation well candidates is carried out with the technical evaluation stage and the economic evaluation stage. The engineering evaluation was carried out by analyzing the history of well production and analyzing the distribution map of the wells in the CP Field. Based on this data, 2 (two) candidate wells were obtained, namely LDK-38 and LDK-108. Then proceed with carrying out technical calculations of Rig capacity, namely by calculating Lifting Loads, Rotating Loads and Circulating Loads and continuing with the preparation of reactivation programs and economic calculations.Based on these calculations, it was found that the need for the Rig Capacity to carry out the reactivation work of the 2 (two) wells was 21 (twenty one) HP, so the Spindle Rig was chosen to do the work because the cost was more economical, which was Rp. 45,000,000, - for the work. per-well reactivation. Therefore, the total cost required for the reactivation of 2 (two) wells is Rp. 90,000,000,-. The reactivation program for the LDK-38 and LDK-108 wells resulted in additional production in the CP Field of + 21.73 BOPD or 5,932 bbl (January - September 2021). In addition, gross revenue of USD 572,000 was obtained (crude oil price of 49 USD/bbl)

Evaluation of Water Channeling Problems and Planning for Its Improvement Using the Remedial Cementing Method and Its Economics in Well AB-30 Field AB PT. Pertamina EP

The AB-30 well is an oil producing well located in the AB Field. Production performance data shows that AB-30 shows excessive water production behavior or is a high water cut production well. In addition, the interpretation of CBL data shows an amplitude value of <10 mV in the productive interval. This condition is an indicator that the primary cementing activity in this well is not good. Therefore, a comprehensive and integrated analytical method is needed to identify the problem of excess water production and to design and plan water shut-off activities through squeeze cementing as an effort to mitigate the problem of high water cut to economic analysis.The research begins by identifying the problem of excess water production, whether caused by water channeling, water coning, changes in water oil contact, or by the physical properties of the reservoir rock. Identification is done through production analysis and water diagnostic plots. The next stage is to evaluate the interpretation of CBL Logging results to strengthen the results of production data analysis. After confirming that the problem of excess water production is caused by poor cement bonding cement, the next step is to calculate the cement work program in order to repair the bad cement bonding. Subsequently, the productive zone interval re-perforation was carried out according to the results of the OH Loh Co Log evaluation. No less important is to conduct an economic analysis as a basis for whether or not this work is feasible.The result of this research is that the water shut-off activity went well and was able to reduce the level of excess water production in the AB-30 well and optimize oil production so as to provide a good economic indicator of oil recovery. Remedial cementing work for bonding repair was carried out at well AB-30. The first work is to close the existing layer, followed by Logging evaluation (CBL-USIT). The evaluation results showed that the cement bonding was good with the CBL amplitude parameter < 10 mV. After that, the productive zone reperforation was carried out. The economy by considering the values of economic indicators such as Pay Out Time and Rate Of Investment showed positive results so that the priority and strategy of well intervention could be continued. The results obtained before the well intervention were 148 BOPD oil production, 97% water cut after well intervention was 880 BOPD average oil production, 0% water cut for 1.5 months

Sand Problem Handling Strategy On Well Ar-02 With Hydraulic Pumping Unit

AR-02 well is one of the oil production wells located in Structure X. This well is produced using the Hydraulic Pumping Unit (HPU) method due to low reservoir pressure as a result of the reduced production capacity of the Y Field formation. In addition, this well has sand problems because the fluid production rate of 96 bfpd exceeds the critical sand flow rate of 66.81 bfpd. The physical properties of reservoir rocks do not cause sand problems because they have a cementation factor of highly cemented (m = 1.99), relatively small clay content (5.4%), compact rock (∆t = 54.16 s/ft), and compact as well as stable formation rock (G/Cb = 14.85x1012 psi2). In solving the sand problem in the AR-02 Well, the Gravel Pack and screen were installed. The correct Gravel size according to the Saucier method is 0.035 inch and the correct screen size according to the Coberly & Wagner, Tauch & Corley, and H. J. Ayre methods is 0.016 inch. The value (G-S) ratio indicates that the selection of Gravel and screen sizes is correct (stable), namely the value (G-S) ratio is at number 5. Redesign of the production scheme due to the installation of the Gravel Pack with the use of HPU pumps at the same setting produces; P due to Gravel installation 40 psi, qfluid after Gravel installation 90 bfpd (previously 95 bfpd), PI after Gravel installation 0.188 (previously 0.198), Min allowable stress 8991.56 psi, Max allowable stress 23420.64 psi, Total stretch 55.42 inch, Over travel 0.391 inch, Plunger stroke 94.97 inch, and Pump Displacement 135.65 bfpd

Uncertainty Assessment for Field Development Study Using Monte Carlo Simulation on Salap Field Multilayer Gas Reservoir

Uncertainty assessment for Field Development Study is often only carried out in a Deterministic Method by only creating scenario sensitivity based on theoretical assumptions without add subsurface risk factors. In the uncertainty assessment model, when a model is made with a variable that only has one value for each sensitivity is called the Deterministic Method. Meanwhile, when a model is made with a variable that has value in the form of a probability distribution, the method is called the Probabilistic Method. In the Probabilistic Method, the probability distribution is influenced by the risk factors, while in the Deterministic Method, these factors have no effect because the input value is only based on theoretical assumption. Uncertainty assessment for the Salap Field Development Study was carried out using the Probabilistic Method Monte Carlo Simulation. The results of the study provide the number of proven reservoirs, volume in place, volume of resources, number of development wells, plateau production period and field life that already accommodates subsurface risk factors and uncertainty in geological-reservoir data. The paper also compares the assessment result between the Probabilistic Method with the Deterministic Method to see how risk factors influenece the study results

OIL RESERVES ANALYSIS IN BATANG FIELD WITH MATERIAL BALANCE METHOD FOR PRESSURE MAINTENANCE

Material Balance method is a concept of material equilibrium with measurement of response from reservoir (pressure) due to production, injection, and influx activities so that it can calculate the appropriate Original Oil in Place. By creating a material balance model, it can be done the development plan of Batang Field with the aim of obtaining cumulative optimum oil production. Batang Field is still feasible to be developed using pressure maintenance scenarios seen from OOIP of 144.3 MMSTB, Recovery Factor of 14.9% and Current Pressure of 70-80 psi.  Pressure Maintenance is a water injection with the aim of replacing the fluid that has been produced so that it is expected to keep the reservoir pressure from falling. Ideally this method requires Voidage Replacement Ratio (VRR) = 1 as the target injection. Economic calculation using Cost Recovery from this scenario shows a positive NVP ($ 2,865,000 USD). Therefore, development projects using Pressure Maintenance can be applied in the field. With this paper, it is hoped that it can increase reserves and  lifespan of the Batang oil field

PERHITUNGAN ESTIMATE REMAINING RESERVE PADA RESERVOIR GAS WATER DRIVE DENGAN METODE MATERIAL BALANCE PADA LAPANGAN KW

Reservoir “X” Lapangan Gas “KW”, merupakan reservoir gas yang telah dikembangkan sejak tahun 2009. Reservoir ini memiliki 2 sumur produksi. Pada tahun 2018, sumur-2 telah ditutup karena produksi air mencapai 311,95 BWPD sehingga produksi air mengurangi produksi gas. Pada 2019, semua sumur ditutup. Reservoir ini telah menghasilkan 5,55 BSCF gas dan 5,4 MBBL air. Di reservoir X, ada rencana untuk dikembangkan. Untuk pengembangan lapangan digunakan metode CARET dan software MBAL untuk menentukan cadangan gas di reservoir. Dari hasil perhitungan dengan menggunakan metode CARET didapatkan nilai OGIP CARET sebesar 8,7763 BSCF dengan koefisien variasi (V) terkecil sebesar 1,47% pada model akuifer kerja hingga kondisi tidak tunak (rD = 10) dan konstanta waktu tak berdimensi (A) dari 1,8 Tahun-1. Dengan menggunakan software IPM-MBAL diperoleh nilai OGIP sebesar 8,7846 BSCF menggunakan metode Havlena Odeh (Water Drive). Dengan menggunakan nilai OGIP dari metode CARET, Estimasi Ultimate Recovery adalah 5,7668 BSCF dan Estimasi Remaining Reserve adalah 0,2168 BSCF. Selain itu, dengan menggunakan nilai OGIP dari perangkat lunak MBAL, Estimate Ultimate Recovery adalah 5,7723 BSCF dan Estimate Remaining Reserve adalah 0,2223 BSCF. Dengan jumlah cadangan gas sisa yang kecil dan produksi air yang berlebihan, reservoir X di Lapangan KW tidak layak lagi untuk dikembangkan.Kata Kunci: CARET; estimate remaining reserve; MBA

Optimization Study of Integrated Scenarios on Cyclic Steam Stimulation (CSS) Using CMG STARS Simulator

Reservoirs in the world contain various types of oil, the difference of these oil types can be seen in the viscosity value and also the value of the API degree. Reservoirs in the U-field contain heavy oil that cannot be produced conventionally so we need the EOR (Enhanced Oil Recovery) method. CSS is a method that uses high-temperature hot steam aimed at reducing the viscosity of the oil so that oil can be produced. In this final project, a simulation is conducted to study the effect of various parameters such as steam quality, injection rate, and cyclic period on CSS and also determine the best scenario for U-field. The simulation begins by determining the best steam quality value, then doing sensitivity to the expected injection rate, followed by sensitivity to the cyclic period. The best scenario results are the integration of optimum parameters, namely steam quality 0.8, the injection rate of 550 BPD, and cyclic period of 20 days injection, 4 days soaking, and 60 days of production produce RF of 35.02%

The Effect of Surfactant Characteristics on IFT to Improve Oil Recovery in Tempino Light Oil Field Indonesia

Water injection has been employed in the Tempino oil field since 1996. The current oil recovery factor is 35% of OOIP. Even though the pressure is still high, the oil production rate has declined rapidly and the water cut is approaching 89%. In order to mobilize  the  oil from the  reservoir  more effectively, surfactant flooding is one of the solutions that can reduce residual oil saturation. Interaction between crude oil and compatible surfactant generates microemulsion,  as an indication of low interfacial tension. Hence the oil is expected to move out of the pore throat easily. In this research, thirty types of surfactants  were evaluated. The hydrophilic  lipophilic  balance (HLB)  was calculated and  the  interfacial tension (IFT)  with the  reservoir fluid  was measured. HLB criteria were established as an indicator of low IFT, which was then tested for Berea core flooding. The results indicate that an HLB between approximately 2.7 and 3.1 (on Davies' Scale) or greater than 11.5 (on Griffin's Scale) gives  low IFT  (~10-3 dynes/cm).  This characteristic  is possesed by surfactant  ethoxy  carboxylate  with a  linear hydrophobic structure.  This surfactant produces a high incremental oil recovery according to Berea core flood tests. The AN2NS and AN3 surfactants recovered 90% and 86% of OOIP respectively

Experimental Study of Polymer Injection on Oil Recovery Factor Enhancement Using Homogenous and Heterogenous Micromodel Porous Media

Polymer injection is one method of chemical enhanced oil recovery, which increase oil recovery by improving mobility when viscous fingering occurred in waterflooding operation. The result of polymer injection is better sweep efficiency, which is presented by more even distribution of the injected fluid. However, in common laboratory evaluation for polymer injection testing, it was no visual observation that presents directly for the fluiddistribution. This experimental study was carried out to visually observe the polymer injection mechanism to displace oil by micromodel as porous media. The micromodel used in this study is transparent acrylic material which was etched by laser engraving technology to create grains that resemble reservoir rocks. The micromodel was saturated by brine water and light oil respectively as initial reservoir fluids. Then, the water was injected as waterflooding operation to displace oil in a micromodel. Hydrolyzed Polyacrylamide (HPAM) polymer with various concentrations were injected into the micromodel as the last scenario. Through this experiment, the movement and distribution of fluids in chemical enhanced oil recovery especiallypolymer injection was able to be recorded for further analysis. Observation for each scenario was done by Digital Image Analysis (DIA). The micromodel flooding results showed that the higher concentration of polymer would give higher oil recovery. The front stability and good distribution of polymer will result in better sweep efficiency, then higher oil recovery will be achieved. This experiment gives result visually how polymer enhance oil recovery. This experiment is expected to be leading innovation for Enhanced Oil Recovery (EOR) laboratory studies in Indonesi