Unlocking Oil Resources without Artificial Lift Using Testing Barge in Tambora Gas Field

2020 ◽  
Author(s):  
J., A. Anggoro
Keyword(s):  
Oil Recovery ◽  
Gas Field ◽  
Artificial Lift ◽  
Oil Resources ◽  
Cumulative Production ◽  
Inspection And Maintenance ◽  
Routine Inspection ◽  
Prime Condition ◽  
Safety Operation ◽  
Mahakam Delta

Tambora field is a mature gas field located in a swamp area of Mahakam delta without artificial lift. The main objective of this project is to unlock existing oil resources. Most oil wells could not flow because there is no artificial lift, moreover the network pressure is still at Medium Pressure (20 Barg). Given the significant stakes, the option to operate the testing barge continuously as lifting tool is reviewed. The idea is to set the separator pressure to 1-3 Barg, so that the wellhead flowing pressure could be reduced to more than 15 Barg which will create higher drawdown in front of the reservoir. The oil flows from the reservoir into the gauge tank, where it is then returned to the production line by transfer pumps. The trial was performed in well T-1 for a week in November 2017 and successfully produced continuous oil with a stable rate of 1000 bbls/d. What makes this project unique is the continuous operation for a long period of time. Therefore, it is important to ensure the capacity of the gauge tank and the transfer pump compatibility with the rate from the well, the system durability which required routine inspection and maintenance to ensure the testing barge unit is in prime condition and to maintain vigilance and responsiveness of personnel. This project started in 2018 for several wells and the cumulative production up to January 2020 has reached 158 k bbls and will be continued as there are still potential oil resources to be unlocked. Innovation does not need to be rocket science. Significant oil recovery can be achieved with a simple approach considering all safety operation, production and economic aspect.

A Superior Shale Oil EOR Method for the Permian Basin

2021 ◽  
Author(s):  
Robert Downey ◽  
Kiran Venepalli ◽  
Jim Erdle ◽  
Morgan Whitelock
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Simulation Modeling ◽  
Lower Cost ◽  
Oil Production ◽  
Oil Wells ◽  
Oil Well ◽  
Shale Oil ◽  
Permian Basin ◽  
Artificial Lift

Abstract The Permian Basin of west Texas is the largest and most prolific shale oil producing basin in the United States. Oil production from horizontal shale oil wells in the Permian Basin has grown from 5,000 BOPD in February, 2009 to 3.5 Million BOPD as of October, 2020, with 29,000 horizontal shale oil wells in production. The primary target for this horizontal shale oil development is the Wolfcamp shale. Oil production from these wells is characterized by high initial rates and steep declines. A few producers have begun testing EOR processes, specifically natural gas cyclic injection, or "Huff and Puff", with little information provided to date. Our objective is to introduce a novel EOR process that can greatly increase the production and recovery of oil from shale oil reservoirs, while reducing the cost per barrel of recovered oil. A superior shale oil EOR method is proposed that utilizes a triplex pump to inject a solvent liquid into the shale oil reservoir, and an efficient method to recover the injectant at the surface, for storage and reinjection. The process is designed and integrated during operation using compositional reservoir simulation in order to optimize oil recovery. Compositional simulation modeling of a Wolfcamp D horizontal producing oil well was conducted to obtain a history match on oil, gas, and water production. The matched model was then utilized to evaluate the shale oil EOR method under a variety of operating conditions. The modeling indicates that for this particular well, incremental oil production of 500% over primary EUR may be achieved in the first five years of EOR operation, and more than 700% over primary EUR after 10 years. The method, which is patented, has numerous advantages over cyclic gas injection, such as much greater oil recovery, much better economics/lower cost per barrel, lower risk of interwell communication, use of far less horsepower and fuel, shorter injection time, longer production time, smaller injection volumes, scalability, faster implementation, precludes the need for artificial lift, elimination of the need to buy and sell injectant during each cycle, ability to optimize each cycle by integration with compositional reservoir simulation modeling, and lower emissions. This superior shale oil EOR method has been modeled in the five major US shale oil plays, indicating large incremental oil recovery potential. The method is now being field tested to confirm reservoir simulation modeling projections. If implemented early in the life of a shale oil well, its application can slow the production decline rate, recover far more oil earlier and at lower cost, and extend the life of the well by several years, while precluding the need for artificial lift.

scholarly journals Optimasi Intermittent Gas lift Pada Sumur AB-1 Lapangan Brownfield

2018 ◽  
Vol 2 (1) ◽  
pp. 32
Author(s):  
Mia Ferian Helmy
Keyword(s):  
Pressure Gradient ◽  
Production Rate ◽  
Flow Rate ◽  
Oil Recovery ◽  
Gas Injection ◽  
Production Method ◽  
Production Flow ◽  
Injection Volume ◽  
Artificial Lift ◽  
Gas Lift

Gas lift is one of the artificial lift method that has mechanism to decrease the flowing pressure gradient in the pipe or relieving the fluid column inside the tubing by injecting amount of gas into the annulus between casing and tubing. The volume of  injected gas was inversely proportional to decreasing of  flowing  pressure gradient, the more volume of gas injected the smaller the pressure gradient. Increasing flowrate is expected by decreasing pressure gradient, but it does not always obtained when the well is in optimum condition. The increasing of flow rate will not occured even though the volume of injected gas is abundant. Therefore, the precisely design of gas lift included amount of cycle, gas injection volume and oil recovery estimation is needed. At the begining well AB-1 using artificial lift method that was continuos gas lift with PI value assumption about 0.5 STB/D/psi. Along with decreasing of production flow rate dan availability of the gas injection in brownfield, so this well must be analyze to determined the appropriate production method under current well condition. There are two types of gas lift method, continuous and intermittent gas lift. Each type of gas lift has different optimal condition to increase the production rate. The optimum conditions of continuous gaslift are high productivity 0.5 STB/D/psi and minimum production rate 100 BFPD. Otherwise, the intermittent gas lift has limitations PI and production rate which is lower than continuous gas lift.The results of the analysis are Well AB-1 has production rate gain amount 20.75 BFPD from 23 BFPD became 43.75 BFPD with injected gas volume 200 MSCFPD and total cycle 13 cycle/day. This intermittent gas lift design affected gas injection volume efficiency amount 32%.

Integrated Subsurface Study to Convert Upside Intrabeta Subzone Stakes into Additional Main Targets in Tunu Gas Field, Mahakam Delta, Indonesia

2021 ◽  
Author(s):  
Dwiki Drajat Gumilar ◽  
Riksa Pribadi ◽  
Dhanny Fadlan ◽  
Ramsyi Faiz Afdhal ◽  
Adnan Syarafi Ashfahani ◽  
...  
Keyword(s):  
Value Creation ◽  
Fluid Dynamic ◽  
Additional Contribution ◽  
Post Mortem ◽  
Main Zone ◽  
Gas Field ◽  
Creation Process ◽  
Dynamic Synthesis ◽  
Mahakam Delta ◽  
Value Creation Process

Abstract "Intrabeta" is a subzone located in the upper part of Tunu Main Zone between MF3-MF6 regional stratigraphic marker. Total cumulative production from this subzone is at 51 Bcf of gas and 4.96 MMBbl of oil. This interval is situated between Tunu Shallow Zone and Tunu Main Zone, which are the main producing intervals of Tunu Field, a giant mature gas field in Mahakam Delta, Indonesia. With Intrabeta reservoir depositional context more dominated by channel facies and more varied production fluid properties, the development of Intrabeta subzone became more challenging and previously classified as upsides. As Tunu Field is getting more matured, the challenge to deliver infill wells that economically profitable become more arduous. Thus, all attempts to give additional value to the future infill wells should be properly assessed. This paper aims to provide a comprehensive summary of how strategic collaboration between static and dynamic synthesis of Intrabeta subzone has given additional contribution in Tunu Field continuous value creation process. The method started by conducting an extensive post-mortem review on all perforated reservoirs in Intrabeta subzone. Insights from the perforated reservoirs that comprise of production behavior, perforation success ratio, cumulative hydrocarbon production and updated portfolio are then utilized to provide initial prolific area map for future candidates maturation. Data coming from the dynamic analysis were then combined with static depositional analysis on how the hydrocarbon was distributed in Tunu Intrabeta subzone. A new structural map that has been corrected from seismic push-down effect due to shallow gas presence above Intrabeta interval was then utilized to map the structurally promising area. Deterministic channel boundaries and possible sweet spots are then identified and ranked based on the development confidence level. Four wells with additional stakes from Intrabeta subzone have been proposed and drilled in Tunu Main Zone. All wells have successfully found the targeted Intrabeta targets with various post-mortem findings. While in some wells significantly better post-drilling results were encountered, in other cases slightly lower results were found due to static channel development and fluid dynamic uncertainties. All the lesson learned gathered from the pilot wells provide valuable insights on future improvement toward better and more robust Intrabeta candidate maturation methodology. The insights gained from this study have given essential understanding of Tunu Intrabeta subzone characteristics and possible future potentials. Furthermore, this paper provides a comprehensive summary, systematical approach and lesson learned in enhancing previously upside potential of Intrabeta subzone in Tunu Main Zone to compelling additional targets in Tunu Main Zone future wells as part of the continuous value creation process in a giant mature gas field.

GAS LIFT IN BASS STRAIT

1985 ◽  
Vol 25 (1) ◽  
pp. 107
Author(s):  
Kathryn J. Fagg
Keyword(s):  
Oil Recovery ◽  
Joint Venture ◽  
Two Phase Flow ◽  
Gas Injection ◽  
Phase Flow ◽  
Gas Distribution ◽  
Two Phase ◽  
Future Developments ◽  
Artificial Lift ◽  
Gas Lift

Gas lift has proved a most effective artificial lift method for the fields operated by Esso Australia Ltd in Bass Strait for the Esso-BHP joint venture. Gas lift is now used to produce approximately 5 st ML/d of the total crude production from the Strait. It has enabled wells to be produced to water cuts higher than 90 per cent, increasing the oil recovery from the fields by up to 35 per cent.Gas lift work in Bass Strait to date has included the use of special packoff gas lift assemblies for wells with sliding sleeves, the development of a tool to assist the opening of the sleeves, improved operating techniques to limit slugging from gas-lifted wells, and the testing of gas lift performance. Gas lifting has been more successful than expected, and as a result, workovers initially planned to install full gas lift strings for older wells have not been necessary. The two phase flow correlations available have been improved to match the performance of the gas-lifted wells. The correlations are now used to design tubing strings with a number of gas lift mandrels prior to running the initial completions and to select the optimum gas injection depth.Future work in gas lift for Bass Strait will involve the optimisation and automation of lift gas distribution on the platforms. Gas lift will also be used for planned future developments, including mini-platforms and subsea completions.

The Vale of Pickering gas fields: Kirby Misperton, Malton, Marishes and Pickering, North Yorkshire, UK Onshore

2020 ◽  
Vol 52 (1) ◽  
pp. 82-93 ◽  
Author(s):  
D. Harrison ◽  
M. Haarhoff ◽  
M. Heath-Clarke ◽  
W. Hodgson ◽  
F. Hughes ◽  
...  
Keyword(s):  
Seismic Data ◽  
Gas Flow ◽  
Lower Carboniferous ◽  
Gas Recovery ◽  
Water Influx ◽  
Water Breakthrough ◽  
Artificial Lift ◽  
Cumulative Production ◽  
Gas Fields ◽  
3D Seismic Data

AbstractThe Vale of Pickering gas fields were discovered over a 20-year period. The development scheme was aimed to deliver 9.3 MMscfd gas to the Knapton Power Station nearby. Cumulative production is 30.3 bcf from an estimated 172 bcf gas initially in place. The gas fields comprise a series of low relief structures at depths around 5000 ft true depth subsea. The primary reservoir is Zechstein Group dolomitized and fractured carbonates of the Permian Kirkham Abbey Formation with average reservoir quality ranges of 12–13% porosity and 0.5–1.5 mD permeability. Secondary reservoirs exist in Carboniferous sandstones directly below the Base Permian Unconformity. The gas is sourced from Lower Carboniferous shales. The fields were discovered using 2D seismic data and subsequent 3D seismic data have been merged to form a 260 km2 dataset. Zechstein production has been limited by early water breakthrough. Artificial lift is planned to enhance the gas flow rate on the Pickering Field and anticipated water influx will be re-injected. If this enhanced gas recovery scheme is successful it can be applied to the other fields. Plans to hydraulically fracture a number of zones in the Carboniferous Lower Bowland Section are in progress.

scholarly journals Rigorous review of electrical submersible pump failure mechanisms and their mitigation measures

2021 ◽  
Vol 11 (10) ◽  
pp. 3799-3814
Author(s):  
Sherif Fakher ◽  
Abdelaziz Khlaifat ◽  
M. Enamul Hossain ◽  
Hashim Nameer
Keyword(s):  
Oil Recovery ◽  
Failure Mechanisms ◽  
Mitigation Measures ◽  
Submersible Pump ◽  
Personal Safety ◽  
Optimum Conditions ◽  
Pump Failure ◽  
Artificial Lift ◽  
Electrical Submersible Pump ◽  
Mitigation Methods

AbstractArtificial lift is a vital part of the life of many oil wells worldwide. Using several artificial lift methods can prolong the life of the wells and increase oil recovery significantly. One of the most applied artificial lift methods nowadays is the electrical submersible pump (ESP). This artificial lift method has the ability to handle large volumes of hydrocarbons and is applicable under many conditions in both offshore and onshore reservoirs. Even though ESP has been applied extensively for many years, it still suffers from many failures due to electrical, mechanical, and operational problems associated with the ESP downhole assembly. Understanding the main reasons behind ESP failures and how to rapidly and effectively avoid and mitigate these failures is imperative to reduce cost and damage and improve operational and rig-personal safety. This research performs a comprehensive review on ESP failure mechanisms and analyzes these failures in order to determine the optimum conditions to operate the ESP. This can help minimize and avoid these failures. Also, should these failures occur, the research proposes several mitigation methods for each failure based on analysis of different field cases worldwide.

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