Gas Injection Optimization to Increase Oil Production at MRA PT. PHE ONWJ

The MRA platform is one of the offshore platforms located in the north of the Java Sea. The MRA platform has 4 production wells, namely MRA-2ST, MRA-4ST, MRA-5, and MRA-6 wells. The 4 production wells are produced using an artificial lift in the form of a gas lift. The limited gas lift at the MRA Platform at 3.1 MMSCFD makes the production of wells at the MRA Platform not optimal because the wells in the MRA Platform are experiencing insufficient gas lift. Optimization of gas lift injection is obtained by redistribution of gas lift injection for each. The results of the analysis in this study indicate that the optimum gas lift injection for the MRA-2ST well is 0.5552 MMSCFD, the MRA-6 well is 1.0445 MMSCFD, the MRA-5 well is 0.7657 MMSCFD, finally the MRA-4ST well with gas injection. lift is 0.7346 MMSCFD. The manual gas lift in the MRA-4ST is also replaced based on an economic feasibility analysis to ensure that the gas lift injection for each well can be kept constant. The redistribution of gas lift carried out by the author has increased the total production rate of the MRA Platform by 11,160 BO/year or approximately USD 781,200/year. Keywords: Gas lift; Insufficient; Optimization

RESERVOIR PERFORMANCE ANALYSIS USING MATERIAL BALANCE METHOD IN GAS FIELD

The RF reservoir is a dry gas reservoir located in Northeast java offshore that has been produced since 2018. The RF reservoir has produced 2 wells with cumulative production until December 2019 is 31.83 BSCF. In January 2018 the gas production rate from the two wells was 36 MMSCFD and the reservoir pressure at the beginning of production was 2449.5 psia, peak production occurred in April 2019 with a gas flow rate of 98 MMSCFD but in December 2019 the gas production rate from both wells decreased to 30 MMSCFD with reservoir pressure decreased to 1607.8 psia. Changes in gas flow rate and pressure in the RF reservoir will affect changes in reservoir performance, so it is necessary to analyze reservoir performance to determine reservoir performance in the future with the material balance method. Based on the results the initial gas in place (IGIP) is 80.08 BSCF. The drive mechanism worked on the RF reservoir until December 2019 was a depletion drive with a recovery factor up to 88% and a current recovery factor (CRF) is 40%. The remaining gas reserves in December 2019 is 39 BSCF and the reservoir will be made a production prediction until December 2032. Based on production predictions of the four scenarios, scenario 2 was chosen as the best scenario to develop the RF reservoir with a cumulative production is 66.1 BSCF and a recovery factor of 82.6%.

Validation of The Cullender and Smith Method for Determining Pressure Loss in The Tubing in Gas Wells

The ability of the reservoir to deliver a certain quantity of gas depends both on the inflow performance relationship and the flowing bottom hole pressure. In order to determine the deliverability of the total well system, it is necessary to calculate all the parameters and pressure drops, one of which in the tubing. Calculation of pressure loss in the tubing is a very important parameter in the stability of fluid flow from the reservoir to the surface. The calculation of pressure loss in the tubing which is most widely used in the field is the Cullender and Smith Method. The purpose of this study is to validate why the Cullender and Smith method is most widely used in the field to determine the pressure loss in the tubing compared to other pressure loss in tubing methods. The methodology used in this study is calculating the pressure loss in the tubing with the Average Temperature and Deviation Factor Method, the Sukkar and Cornel Method, and the Cullender and Smith Method. After calculating the pressure loss in the tubing using each of these methods, then comparing the percent error of the calculation method with the results in the well. The data used in the calculation is the data from the MZ Field from 7 wells in the East Kalimantan area. The results of the average error percentage obtained from this study are the Average and Deviation Factor Method is 5.38%, the Sukkar and Cornell Method is 5.65%, and the Cullender and Smith Method is 3.83%. From this study, it can be said that the Cullender and Smith Method to be valid or the most accurate method for used in the field compared to other methods due to resulting the smallest percent error from the calculation.

Modeling the Combined Effect of Salt Precipitation and Fines Migration on CO2 Injectivity Changes in Sandstone Formation

Carbon dioxide, CO2 emissions have risen precipitously over the last century, wreaking havoc on the atmosphere. Carbon Capture and Sequestration (CCS) techniques are being used to inject as much CO2 as possible and meet emission reduction targets with the fewest number of wells possible for economic reasons. However, CO2 injectivity is being reduced in sandstone formations due to significant CO2-brine-rock interactions in the form of salt precipitation and fines migration. The purpose of this project is to develop a regression model using linear regression and neural networks to correlate the combined effect of fines migration and salt precipitation on CO2 injectivity as a function of injection flow rates, brine salinities, particle sizes, and particle concentrations. Statistical analysis demonstrates that the neural network model has a reliable fit of 0.9882 in R Square and could be used to accurately predict the permeability changes expected during CO2 injection in sandstones.

Risk Mitigation and Mapping on Tubular System During Microbial Huff and Puff Injection Coupled with Lean Six Sigma Approach at Field X

Increasing demand of oil in Indonesia is in contrast with the decreasing oil production every year. Enhanced oil recovery (EOR) has become one of the most favorable method in maximizing the production of mature fields with various applications and research has been done on each type, especially microbial EOR (MEOR). “X” field is a mature oil field located in South Sumatra that has been actively producing for more than 80 years and currently implementing MEOR using huff and puff injection. However, there are some potential risks regarding MEOR processes that may inhibit the production by damaging the well’s tubular system, particularly microbially induced corrosion (MIC). This study reviews the risk mitigation and mapping to prevent corrosion on tubular system during MEOR huff and puff processes, equipped with the approach of Lean Six Sigma.The mitigation and mapping process follow the framework of define, measure, analyze, improve, and control (DMAIC). It starts with defining the problem using supplier-input-process-output-customer (SIPOC) diagram after all the field data necessary has already been collected, then measuring the corrosion rate model using ECE™ software as well as conducting sensitivity analysis of the fluid rates. The analyze phase involves constructing fishbone diagram to identify the root causes, comparison with industry’s specification and standard, and analysis of chromium effect on corrosion rates. Further simulation is conducted to support the analysis and to ensure the improvements and sustainability of the design selection.Based on the simulation results, the normal corrosion rate ranging from 0.0348 – 0.039 mm/year and the pH is around 4.03 – 5.25, while the ±30% fluid rate sensitivity results shown that the change of water flowrate is more sensitive than oil flowrate with the corrosion rate approximately 0.0275 – 0.048 mm/year. The fishbone diagram identifies that material selection and environmental condition as the main root causes, then corrosion resistant alloy (CRA) is used in the tubing string to prevent corrosion in the future by using super 13Cr martensitic steel (modified 2Ni-5Mo-13Cr) as the most suitable material. Further simulation on chromium content supports the selection that corrosion rate can be reduced by adding the chromium content in the steel. The completion design is then capped with choosing the Aflas® 100S/100H fluoro-elastomer as the optimum material for packer and sealing. Overall, the Lean Six Sigma approach has been successfully applied to help the analysis in this study.

Evaluation and Optimization of Bypassed Oil in Carbonate Reservoir at Mature Field with Integration of Saturation Log and Cement Bond Quality

AA field is a unitized asset operated by Corporate Oil Company since May 2018. The main producing formation of AA field is a reef build-up carbonate reservoir. The field has been on production since 2004 with OOIP of 297 MMSTB. As of November 2019 the cumulative production was estimated 120.7 MMSTB with RF of 41%. The carbonate reservoir has properties with relatively high heterogeneity –both vertically as well as laterally – which leads to production variation of the wells. The production performance shows an estimated 30% decline and significantly increasing water-cut. The production data shows a much faster water production compared with the cumulative production, which is also the greatest challenge in the AA field.There are several key contributing factors for the water production in AA field:Water channeling behind casing due to poor cement bond. This is supported by Chan Plot analysis.Uneven production of the wells leading to varying water rise and introduces difficulty in water contact determination.Water coning due to production exceeding the critical rate.Several efforts have been performed to optimize production, namely: identification of the potential of remaining hydrocarbon (bypassed oil) in the wells by evaluating current saturation evaluation through downhole surveillance, estimation of current water contact and cement bond improvement.The preparation steps of the production optimization process are summarized below:Screening of Candidate WellsEvaluation of Cement Bond QualityWellsite Execution for Bypassed Oil EvaluationWell PreparationOptimum C/O Log to Evaluate Current Saturation and to Identify Bypassed Oil ZonesBypassed Oil Interval ProductionThis section discusses one of successful cases in the production optimization effort implemented in the AA- field.AA-12 wellThe last production of AA-12 well was 84 BOPD. Chan plot showed possibility of water channeling, which was supported by CBL result. The zone of existing perforation interval was indicated to have “free pipe” behind the casing. Remedial cementing was then performed until sufficient zonal isolation was obtained. After subsequent CBL confirmed good zonal isolation, C/O log was then performed. The C/O log result indicated several reservoir zones with potential bypassed oil. The new production interval was selected based on following consideration: So between 55-60%, height above current OWC of 185 ft (56 m), distance to the adjacent wells of 1306 ft (398 m), porosity 12-17% and Production test of the new perforation resulted in 2186 BOPD with 0% water-cut.

Optimization of Cyclic Steam Stimulation Process Using Response Surface Methodology

Heavy oil has characteristics such as API gravity 10-20 and high viscosity (100-10,000 cp) at reservoir temperature. Several methods have been successfully applied to produce these reserves, such as cyclic steam stimulation (CSS). Cyclic steam stimulation is a thermal injection method that aims to heat the oil around production wells. This paper presents the investigation regarding CSS application in heavy oil using Response Surface Methodology. Several scenarios were done by varying the operating conditions to obtain the most realistic results and also evaluating the factors that most influence the success of CSS process. Optimization is performed to find the maximum recovery factor (RF) value and minimum steam oil cumulative ratio (CSOR). The operating parameters used are CSS cycle, steam injection rate, and steam quality. Then statistical modeling is carried out to test the most important parameters affecting RF and CSOR for 10 years. The simulation results show that the CSS cycle, steam injection rate, and steam quality affect the RF and CSOR. The maximum RF results with the minimum CSOR were obtained at 39 cycles, an injection rate of 300 bbl/day, and a steam quality of 0.9 with an RF and CSOR value is 24.102% and 3.5129 respectively.

Integrated Drilling Optimization A Success Story in the Basin of North Africa

Drilling optimization objective was to reduce costs, improve wellbore conditions and integrity for increasingly challenging reservoirs while establishing maximum safety performance and environmental custodianship. Even though the final result of a drilling operation is easily observed, what almost always goes unnoticed is the complexity of the issues involved in the planning and execution of a drilling operation and the number of topics involved in such a process.In this paper, as case study of the exploration drilling in Hamada region, North Africa has been evaluated. Over the period of 2006 to 2011, continued drilling improvement was achieved. Key elements in the optimization included focus on management drilling team structure, engineering well planning, improvements on managing drilling operations such as on site safety management practices, and also post drill analysis to implement lesson learn for the next well to be drilled.As the result, while drilling 26 wells during the 2006 until 2011, drilling days were successfully reduced from 87 days (first well) to the average 40 days, and very good safety record performance.

Comparison of Different Gases Injection Techniques for Better Oil Productivity

There are many known enhanced oil recovery (EOR) methods and every method has its criteria to use it. Some of those methods are gas injection such as CO2 injection, N2 and hydrocarbon gas injection. Where the CO2 has been the largest contributor to global EOR. Gas injection can be classified into two main types; continues gas injection (CGI) and water alternating gas injection (WAG). The objective of this research is to propose initial gases injection plan of the X field to maximize the total oil recovery. The feasibility study of different gases to maintain pressure and optimize oil recovery have been examined on a simple mechanistic reservoir model of considerably depleted saturated oil reservoir. In order to maximize the total oil recovery, the simulation study was conducted on 3-phase compositional simulation model. For more optimization, a sensitivity study was conducted on the injection cycling and component ratios. A sensitivity study was also conducted on the following parameters to study their effects on the overall field’s recovery such as flow rate and bottom-hole pressure. Results obtained in this paper shows that, the WAG CO2 injection was found to be significantly more efficient than different gas injection and continues gas injection. The oil recovery depends not only on the fluid-to-fluid displacement but also on the compositional phase behavior.

Evaluation And Optimization Production Of Low Permeability Carbonate Reservoir By Hydraulic Fracturing In “Jaso Field”

“Jaso field” is located the South Sumatra basin, Indonesia. The lithology of this field is dominated by limestone / carbonate reservoirs with varying permeability (low / tight to high / porous). Acid Fracturing stimulation has been applied to develop this field, because in ideal conditions (with the solubility test between acid and formation > 80%) wormholes will be made in the formation to increase reservoir conductivity and productivity. However, in the Jaso oil field, in some special cases, acid injection did not provide satisfactory results for increasing well conductivity and productivity.In this thesis, we conduct research and evaluation of wells in Jaso field. For example: JS-28, JS-11 and JS-40 are oil wells in the Jaso field with low / narrow reservoir permeability and production rates. Stimulation has been carried out in the JS-28 well, but the results are still below the acid expectation even though the intermediate solubility test (solubility test) is more than 88%.Hydraulic Fracturing with the sandfracturing method (injecting sand proppant with high pressure and exceeding the gradient fracture) has been successfully applied to three wells in the Jaso Field by increasing the oil production rate by more than 100 bopd per well. With this case study, we find that the application of hydraulic fracturing (sandfracturing) with thrusters is not limited to sandstone / sandstone reservoirs, but that this method can be successfully applied to increase the conductivity and productivity of carbonate reservoirs (in special cases) taking into account several parameters of integrity. reservoir wells and characteristics.