Journal of Earth Energy Engineering
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Analysis of Surfactant and Polymer Behavior on Water/Oil Systems as Additives in Enhanced Oil Recovery (EOR) Technology through Molecular Dynamics Simulation: A Preliminary Study
Full text linkThe decline in oil production has led to the development of the Enhanced Oil Recovery (EOR) technology to increase oil production. Chemical injection is one of the methods in EOR by injecting surfactants or polymers into reservoir wells. To understand the properties and dynamics of surfactants and polymers at the nanoscale, computational studies using molecular dynamics simulation were carried out. In this study, surfactant Sodium Dodecyl Benzene Sulfonate (SDBS) and polymers such as Polyacrylamide (PAM) were used to investigate their effect on the oil-water interface system at the atomic level. Molecular dynamics simulation was carried out using Large-scale Atomic/Molecular Massively Parallel Simulator (LAMMPS) to calculate the diffusion coefficient and Interface Formation Energy (IFE) value for the addition of the surfactant and polymers. The simulation results show that the addition of the surfactant and polymers affects the water-oil interface system differently. The diffusion coefficient results indicates that there are strong interactions between SDBS and dodecane with D of 0.01358. While for PAM, the interactions with water are more significant with D of 0.059. The results of the IFE calculation value also show that the addition of SDBS and PAM makes the water-oil interface system more stable with the negative IFE value of -197.51 and -13.13 Kcal/mol respectively. The results of this study will be used as a reference and a basis for designing new surfactants or polymers that will led to more oil recovery
THE CALCULATION OF EVAPORATION LOSS IN TANK Y AND TANK Z AT PT X PRABUMULIH
No full textCalculation Evaporation Loss (Fixed Roof Tank) on Tank Y and Tank Z in SA Field, PT X Prabumulih. The calculation of evaporation loss consists of breathing loss and working loss. By calculating breathing loss and working loss, it can be known the losses that occur in a tank. The most significant parameters in influencing breathing loss are temperature and ullage tanks, while parameters that greatly affect working loss are true vapor pressure and trhoughput. After calculating, the total losses that occurred in Tank Y and Tank Z were obtained as much as 3.46 Bbl / day or 1,261.41 Bbl / year, if assumed with the Indonesian Crude Price (ICP) price of crude oil per barrel is currently US $ 117.62 then the loss incurred in Tank Y and Tank Z is Rp. 2,209,762,045 / year
Numerical Simulation Study of Steam Injection Optimization in Shallow Reservoir
Full text linkIn an EOR project, process improvement must be continually pursued since EOR is often marginally profitable. In steamflood EOR project, steam injection rate is very important parameter to ensure that each pattern reach maturity within a certain early period that result in high oil recovery and meet the economic hurdles. In particularly shallow formation settings, steam injection target is often difficult to achieve because limited by fracturing pressure to avoid breaching the cap rock and creating environmental problem. In this study we simulate steam injection in a typical heavy oil reservoir (high API, shallow depth, low pressure) to enable optimization of steam injection. A model has been built using typical shallow reservoir in using Builder-CMG. Wellan data, fluid model and operating conditions (injection strategy, steam quality) and expected/ forecasted performance. CMOST package is then used to design optimization study by varying the steam injection rate. The best scenario is based on the lowest reservoir pressure and cumulative SOR. We created three development options: regular inverted 7-spot 15.5-acre pattern, horizontal well and pattern size reduction (PSR). From this numerical study it is found that for the case studied, steam injection rate can be ramped up from 250 - 300 BSPD within 6-7 years, followed by peak production. A wind down injection rate to 0 can be used after this peak production to achieve CSOR target of 3-4 bbl of steam/bbl of oil. If a quicker SBT is required, then more steam injectivity is needed to put underground. Several scenarios can be considered as follow: (1) reducing the pattern size (thus adding steam via additional injection wells) and (2) utilizing horizontal wells
Maximum Allowable Annular Surface Pressure (MAASP) Standards Calculations Study; a Field Case Study
No full textWell integrity failures may arise during the production phase of a well in a field. Those failures could create a Sustained Casing Pressure (SCP), a pressure that is measurable at the wellhead that can not be bled-off. SCP has to be addressed carefully to avoid any uncontrolled fluid flow to other formation or to surface. To maintain SCP value from degrading the other barrier integrity, the pressure threshold should be known and maintained for each annulus in a well. The maximum pressure threshold known as Maximum Allowable Annular Surface Pressure (MAASP).
This case study will calculate MAASP from three wells in X field using three known method as outlined in API RP90-2 and ISO 16530-1. API RP 90-2 define two methods in calculation MAASP (known as MAASP – Maximum Allowavle Wellhead Operating Pressure), Simple Derating Method (SDM) and Explicit Derating Method (EDM).
The result then compared and evaluted to know the differences, trend of MAASP for each methods, and create a generalization of MAASP/depth for field rule of thumb. For A annulus, the MAASP obtained using API RP90-2 SDM and EDM method is always greater than that obtained using the ISO 16530-1 method. However, for B annulus, the MAASP obtained using the API RP 90-2 SDM method varies, occasionally being greater or less than the ISO 16530-1 method. While in C annulus, the MAASP obtained using the API RP 90-2 SDM and EDM methods is always less than the ISO 16530-1 method. The MAASP/depth generalization will be presented for MAASP ISO 16530-1
Pressure Transient Analysis using Generated Simulation Reservoir Data for Dual Porosity Model of Naturally Fractured Reservoir
Full text linkA naturally fractured reservoir today plays a significant role in improved worldwide oil and gas production. More than half of the resource is mostly found in this reservoir. In this reservoir, there are two porous media: the matrix, which acts as the fluid source in this reservoir, and the fractures, which act as the fluid network that flows to the wellbore. Many authors have researched works to model this reservoir. There are two models are done in this study, such as Warren and Root model, where the fluid flow mechanism matrix to fractures is known as pseudosteady-state flow and the Kazemi-Gilman model is known as transient interporosity flow. Reservoir engineers generally utilize pressure transient analysis to determine this reservoir's characteristics. The purpose of this study is to assess whether it is feasible to verify the parameters of the reservoir for pressure transient analysis using a synthesis simulation model. It also aims to observe how reservoir parameters behave in relation to the characteristics of naturally fractured reservoirs by utilizing various values for porosity, permeability, and fracture spacing
Evaluation of the use of Water Alternated Gas Injection for Enhanced Oil Recovery
Full text linkHydrocarbon can be naturally produced from underneath fractured sandstone when pressure can no longer force fluids to the surface facilities. A satisfactory recovery factor for this production was conducted through the cost-effective enhanced oil recovery (EOR) method. Water alternated gas (WAG) injection is a promising EOR technique that combines the advantages of waterflooding and gas injection to achieve better mobility control, improved sweep efficiency, and overall recovery from the given reservoir. Therefore, this study aims to investigate the relationship of a miscible WAG to a core flood model using numerical simulation techniques (Eclipse Reservoir Simulator – Black Oil Model Option). In this case, reservoir X consisting of three wells drilled 15 years after the initial forecast showed that production cannot be sustained by natural depletion. Furthermore, the optimal WAG ratio was selected with different simulation scenarios using oil recovery factors to perform 12 simulation runs and study the influence of the WAG cycle period. The most effective WAG cycle scenario was 90W-30G with an oil recovery factor of 0.54684 (54.68 %) and cumulative production of 14.987MMSTB. The 30W-90G produced the lowest oil recovery factor and cumulative production of 0.47468 (47.47%) and 12.996 MMSTB, respectively. Therefore, a higher water cycling period is required for better oil recovery. The recovery is also enhanced by lowering the rate of water to gas injection. The results showed that despite the predicted higher recovery factor, a lower WAG ratio indicated a potential of relatively low-pressure maintenance which can affect future recovery from the reservoir
Integrated Completion Study for Hpht Sour Gas Well Development in Carbonate Reservoir X
Full text linkThe increasing need for energy sources and the decreasing available reserves have promoted oil and gas companies to explore and manage marginal reservoirs, such as the sour gaseous environment. This is to maintain the balance of energy supply and demand. Due to the supply of Natuna Gas Field, the gap in gas supply-demand is likely to decrease by 20%, as regards the example of a potential sour gaseous environment (Batubara, 2015). Therefore, the immediate development of this potential source is very relevant. The sour field approximately shares 40% of Indonesia’s total gas reserve with 75% recovery, at an estimated OGIP of 222 TSCF. However, this environment is economically unproductive due to having high carbon dioxide (CO2) and hydrogen sulfide (H2S) contents, which are toxic and corrosive. Based on previous studies, the X-reserves reportedly contained 32% CO2 and 7072 ppm H2S, with fluid gravity of 42 API. This discretionary source of CO2 was recently brought into production from a well with a depth of 8400 ft, perforated at a limited interval of 7100 to 7700 ft. The harsh environment presented many challenges to the completion of the design, as well as the need to incorporate corrosion effects with unique equipment and material selection for the tubular structure. Therefore, this study aims to determine reservoir fluids and production performance, as well as also predict the corrosivity of dissolved CO2 in the natural gas. With the simulation and prediction, the proper material and equipment selection was obtained, based on the required sour service. The results showed that the wet gas reservoir of the X-field produced an optimum rate of 19.1063 MMSCFD. For the completion of the design, Nickel Alloy SM2535 or SM2242 was needed, due to damages in form of corrosion and pittin
ROP Prediction with Supervised Machine Learning; a Case Study : Supervised Machine Learning
No full textOptimum drilling penetration rate, known as the rate of penetration (ROP) has played a big role in drilling operations. Planning the well ROP always becomes a challenge for drilling engineers to calculate the drilling time needed for the section. Optimum ROP is achieved when the time to drill the section is as planned. Many empirical approaches were develop to model the ROP based on the drilling parameters, and might not always match the actual ROP. In some cases, the actual ROP was slower than planned, which may increase the drilling cost, which needs to be avoided. Hence, some approaches using artificial intelligence (AI), and supervised machine learning have been develop to overcome it. Supervised machine learning is used to developed a ROP model and ROP prediction for one of the development fields, based only on two wells drilling parameters data. The model was trained using Gradient Boosting, Random Forest, and Support Vector Machine. Drilling parameter test data then is used to validate the model. The model of Random Forest shows a good or promising result with R2 of 0.90, Gradient Boosting shows R2 of 0.86, and Support Vector Machine with R2 0.72. Based on the models generated, the Random Forest has shown a good trend which could be used for modeling ROP in the future development well
Predicting Rate of Penetration and optimization Weight on bit using Artificial Neural Networks
No full textObtaining the maximum Rate of Penetration (ROP) by optimization drilling parameters is the aim of every drilling engineer. This is because it could save time, reduce cost and minimize drilling problems. However, ROP depends on a lot of parameters which lead to difficulties in its prediction. Therefore, it is necessary and important to investigate a solution predicting ROP with high accuracy to determine the suitable drilling parameters. In this study, a new approach using Artificial Neural Network (ANN) has been proposed to predict ROP from real – time drilling data of several wells in Nam Rong - Doi Moi field with more than 900 datasets included important parameters such as the weight on bit (WOB), weight of mud (MW), rotary speed (RPM), standpipe pressure (SPP), flow rate (FR), torque (TQ). In the process of training the network, algorithms and the number of neurons in the hidden layer were varied to find the optimal model. The ANN model shows high accuracy when compared to actual ROP, therefore it can be recommended as an effective and suitable method to predict the ROP of other wells in the research area. Besides, base on the proposed ANN model, authors carried out experiments and determind the optimal weight on bit value for the drilling interval from 1800 to 2300 m of wells in Nam Rong Doi Moi fiel
Evaluation of Remaining Gas Reserves Using the Material Balance Method for Planning Gas Field Development
Full text linkThe demand of energy in the world will increase due to the increasing population and industrial activity. Currently, the fossil energy is relatively cheaper compared to other energy sources, especially natural gas. The “CJ” field is a gas field located in the South Sumatra Basin, Indonesia with a reservoir located in the Basalt Telisa Limestone (BTL) formation. This gas field consists of 3 wells namely Well GTA-1, GTA-2, and GTA-3 which produced from 1951 to 1991. In 1991 the three wells were suspended and will be reopened in 2021 due to request from buyers for 10 years. The research method is collecting and consisting of data on reservoir, production, and physical properties of the gas. The next step is to calculate the value of the gas formation volume factor and Z-factor (gas compressibility factor/gas deviation factor) with various pressures. After it, determine the type of drive mechanism using the Cole Plot method. After knowing the type of drive mechanism, determine the current OGIP value using the material balance method. If the OGIP value is known, the next calculation is the Recovery Factor (percentage of the amount of gas that can be produced to the surface), Ultimate Recovery (UR) and finally the value of Remaining Reserve (RR). Based on the calculation, the OGIP value obtained by the material balance method with P/Z vs GP plots is 83.46 BSCF, Recovery Factor of 80.22%, Ultimate Recovery of 66.96 BSCF, and remaining gas reserve 15.45 BSCF. The maximum flow rate could be obtained by remaining reserve divided contract period. From these results, the maximum reserve value that can be produced to the surface for 10 years is 4.23 MMSCFD. Therefore “CJ" Field meet the needs of buyer to fulfil the requirement number which is only 4 MMSCFD