Full Field EOR Implementation of A Low Cost Surfactant Continuous Injection at Arahan-Banjarsari, South Sumatra

2020 ◽  
Author(s):  
T. Ariadji
Keyword(s):  
Oil Recovery ◽  
Micellar Solution ◽  
Low Cost ◽  
Spontaneous Imbibition ◽  
Successful Implementation ◽  
Full Field ◽  
Chemical Eor ◽  
Reservoir Conditions ◽  
Water Cut ◽  
Continuous Injection

The objective of this paper is to describe a series of laboratory work results in conjunction with successful implementation of the surfactant (micellar) continuous injection in the Muara Enim sand of the Arahan-Banjarsari Field, South Sumatra. A series of lab tests were conducted using field cores and fluids taken from the Arahan-Banjarsari (AR-BS) field. The tests included phase behavior, mixture viscosity measurement, spontaneous imbibition, and static isotherm adsorption tests. Several surfactant formulas had been tested to find the most consistent and most suitable to the reservoir conditions. The surfactant injection was started in March 2009 into three AR wells. The injection was divided into 4 stages with initial concentration of 0.45% and the final concentration of 0.1%. Total volume of micellar solution injected in 110 days was 52,365 bbls. An increase in oil production was observed not only in two AR wells but also in 8 wells in the neighboring BS field (500 meters distance) after 140 days since injection of micellar solution started with injection rates of 200-250 bpd. Two BS wells were reopened and produced 28% and 54% water cut (the water cut before the two wells were shut in was 19% and 76%). This micellar solution injection managed to decrease the decline rate of 70% to 26% per year, increase production rate from AR and BS fields from 90 bopd to a peak of 220 bopd in 5 months since injection started, and reserves enhancement of 183 M bbls (10% OOIP) during 3.5 years of continuous injection. The low cost, full scale chemical EOR leads to changes in the common understanding about micellar flooding and shows a high impact on oil recovery of 183 Mbls (AB-5c sand with OOIP of 1.8 MMSTB).

scholarly journals Comparative Study of Using Sea-Water for Enhanced Oil Recovery in Carbonate and Sandstone Reservoirs: Effects of Temperature and Aging Time on Oil Recovery

2018 ◽  
Vol 7 (2) ◽  
pp. 1-13
Author(s):  
Madi Abdullah Naser ◽  
Mohamed Erhayem ◽  
Ali Hegaig ◽  
Hesham Jaber Abdullah ◽  
Muammer Younis Amer ◽  
...  
Keyword(s):  
Aging Time ◽  
Oil Recovery ◽  
Sea Water ◽  
Essential Element ◽  
Recovery Process ◽  
Spontaneous Imbibition ◽  
Effect Of Temperature ◽  
Injection Process ◽  
Reservoir Conditions ◽  
The Impact

Oil recovery process is an essential element in the oil industry, in this study, a laboratory study to investigate the effect of temperature and aging time on oil recovery and understand some of the mechanisms of seawater in the injection process. In order to do that, the sandstone and carbonate cores were placed in the oven in brine to simulate realistic reservoir conditions. Then, they were aged in crude oil in the oven. After that, they were put in the seawater to recover, and this test is called a spontaneous imbibition test. The spontaneous imbibition test in this study was performed at room temperature to oven temperature 80 oC with different sandstone and carbonate rock with aging time of 1126 hours. The result shows that the impact of seawater on oil recovery in sandstone is higher than carbonate. At higher temperature, the oil recovery is more moderate than low temperature. Likewise, as the aging time increase for both sandstone and carbonate rocks the oil recovery increase. 

Nanoparticles EOR Aluminum Oxide (Al2O3) Used As a Spontaneous Imbibition Test for Sandstone Core

2019 ◽  
Author(s):  
Mohammed A. Samba ◽  
Hafsa A. Hassan ◽  
Mahjouba S. Munayr ◽  
Moataz Yusef ◽  
Abdelkareem Eschweido ◽  
...  
Keyword(s):  
Aluminum Oxide ◽  
Oil Recovery ◽  
Room Temperature ◽  
Spontaneous Imbibition ◽  
Chemical Flooding ◽  
Secondary Recovery ◽  
Chemical Eor ◽  
Change Temperature ◽  
Al2o3 Concentration ◽  
Polymer Surfactant

Abstract There are three types of oil production energy operations, primary recovery, secondary recovery and enhanced oil recovery (EOR). EOR consider as the last period for production operations. Where the EOR classify into many types such as thermal injection, gas injection, microbial EOR and chemical flooding. Chemical flooding classified into many types such as polymer, surfactant, alkaline and nanoparticles (NP). NP can be classified into many types such as Iron Oxide (Fe2O3), Aluminum Oxide (Al2O3) and Magnesium Oxide (MgO) etc. In this study NP Aluminum oxide (Al2O3) were used to enhance the oil recovery. The main objective of this study is to use the Nanoparticles EOR (Al2O3) and know it is effect on increasing the extraction of oil from cores. The big motivation of using Al2O3 that it is easy to extract it from raw clay. However, the raw clay is available in Libya and using it will be more economic than using other method of chemical EOR. Nanoparticles EOR Aluminum oxide (Al2O3) used as a spontaneous imbibition test for sandstone core samples after saturated by crude oil. A spontaneous imbibition test consisting of two scenarios of nanoparticle solution (Al2O3) with change temperature and compared with one scenario of distilled water. The spontaneous imbibition test was performed in this study at room temperature to oven temperature (30C°, 40C°, 50C°, 60C°, 70C°). The results shown that the oil recovery increases with the increase of the concentration of nanoparticle (Al2O3) and increase the temperature. The higher oil recovery was 76.04% at NP (Al2O3) concentration 1%. Finally, oil swelling and adsorption (NP (Al2O3) with oil drops) have been noticed during the extraction of oil. Thus, the gravity force will be higher than the capillary force.

Alkaline/Surfactant/Polymer Flood: From the Laboratory to the Field

2011 ◽  
Vol 14 (06) ◽  
pp. 702-712 ◽  
Author(s):  
W. M. Stoll ◽  
H.. al Shureqi ◽  
J.. Finol ◽  
S. A. Al-Harthy ◽  
S.. Oyemade ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Test Tube ◽  
Full Field ◽  
Asp Flooding ◽  
Chemical Eor ◽  
Single Well ◽  
Hydrocarbon Gas ◽  
Reservoir Simulation Model ◽  
Petroleum Development ◽  
Alkaline Surfactant Polymer

Summary After two decades of relative calm, chemical enhanced-oil-recovery (EOR) technologies are currently revitalized globally. Techniques such as alkaline/surfactant/polymer (ASP) flooding, originally developed by Shell, have the potential to recover significant fractions of remaining oil at a CO2 footprint that is low compared with, for example, thermal EOR, and they do not depend on a valuable miscible agent such as hydrocarbon gas. On the other hand, chemical EOR technologies typically require large quantities of chemical products such as surfactants and polymers, which must be transported to, and handled safely in, the field. Despite rising industry interest in chemical EOR, until today only polymer flooding has been applied on a significant scale, whereas applications of surfactant/polymer or alkaline ASP flooding were limited to multiwell pilots or to small field scale. Next to the oil-price fluctuations of the past two decades, technical reasons that discouraged the application of chemical EOR are excessive formation of carbonate or silica scale and formation of strong emulsions in the production facilities. Having identified significant target-oil volumes for ASP flooding, Petroleum Development Oman (PDO), supported by Shell Technology Oman, carried out a sequence of single-well pilots in three fields, sandstone and carbonate, to assess the flooding potential of tailor-made chemical formulations under real subsurface conditions, and to quantify the benefits of full-field ASP developments. This paper discusses the extensive design process that was followed. Starting from a description of the optimization of chemical phase behavior in test-tube and coreflood experiments, we elaborate how the key chemical and flow properties of an ASP flood are captured to calibrate a comprehensive reservoir-simulation model. Using this model, we evaluate PDO's single-well pilots and demonstrate how these results are used to design a pattern- flood pilot.

Experimental and Numerical Assessment of Chemical Enhanced Oil Recovery in Oil-Wet Naturally Fractured Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0706-0719 ◽  
Author(s):  
Bernard Bourbiaux ◽  
André Fourno ◽  
Quang-Long Nguyen ◽  
Françoise Norrant ◽  
Michel Robin ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Scale Effects ◽  
Fractured Reservoirs ◽  
Spontaneous Imbibition ◽  
Cocurrent Flow ◽  
Chemical Additives ◽  
Fluid Saturation ◽  
Aqueous Solvent ◽  
Chemical Eor

Summary Among various ways to extend the lifetime of mature fields, chemical enhanced-oil-recovery (EOR) processes have been subject of renewed interest in the recent years. Oil-wet fractured reservoirs represent a real challenge for chemical EOR because the matrix medium does not spontaneously imbibe the aqueous solvent of chemical additives. The present paper deals with chemical EOR by use of wettability modifiers (WMs). The kinetics of spontaneous imbibition of chemical solutions in oil-wet limestone plugs and mini-plugs was quantified thanks to X-ray computed-tomography (CT) scanning and nuclear-magnetic-resonance (NMR) measurements. Despite the small size of samples and the slowness of experiments, accurate recovery curves were inferred from in-situ fluid-saturation measurements. Scale effects were found quite consistent between mini-plugs and plugs. During a second experimental step, viscous drive conditions were imposed between the end faces of a plug, to account for the possibly significant contribution of fracture viscous drive to matrix oil recovery. The recovery kinetics and behavior, especially the occurrence of countercurrent and cocurrent flow, are interpreted through the analysis of modified forces in the presence of a diffusing or convected WM that alters rock wettability and reduces water/oil interfacial tension (IFT) to a lesser extent. This work calls for an extensive modeling study to specify the conditions on chemical additives and recovery-process implementation that optimize the recovery kinetics.

scholarly journals Development of Ultralow Interfacial Tension Lignosulfonate from Kraft Black Liquor for Enhanced Oil Recovery

2021 ◽  
Vol 53 (2) ◽  
pp. 210210
Author(s):  
Muhammad Mufti Azis ◽  
Fergie Febrina ◽  
Ignesti Anindia ◽  
Galuh Almas Darmawati ◽  
Desi Amalia Fenyka ◽  
...  
Keyword(s):  
Interfacial Tension ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Large Scale ◽  
Low Cost ◽  
Black Liquor ◽  
Sodium Lignosulfonate ◽  
Kraft Black Liquor ◽  
Chemical Eor ◽  
Ultralow Interfacial Tension

Indonesia aims to implement large-scale enhanced oil recovery (EOR) to increase the national oil production. Chemical EOR is a promising technology to boost the production of old reservoirs with the aid of surfactants and polymers. Thus, the production of low-cost EOR surfactants from local resources with acceptable performance is highly attractive. The objective of the present work was to demonstrate the development of low-cost lignosulfonate surfactant production from kraft black liquor (BL). First, lignin was isolated from black liquor using a novel CO2 bubbling technique, followed by addition of coagulants. Next, sodium lignosulfonate (SLS) was synthesized from the resulting lignin, followed by formulation of SLS with octanol and palm fatty acid distillate (PFAD) soap to obtain an ultralow interfacial tension (IFT) surfactant. The initial IFT value of the SLS solution was already high at 0.7 mN/m. After formulation, the composition SLS:PFAD soap:octanol = 70:22:8 (wt%) improved the IFT value to 3.1 10-3 mN/m. An ultralow IFT in the range of 10-3 mN/m as achieved here fulfills the required IFT value for EOR surfactant.

An Australian first initiative to re-develop the first commercial onshore oilfield into a CO2 miscible-EOR project

2019 ◽  
Vol 59 (1) ◽  
pp. 179
Author(s):  
Stephanie Barakat ◽  
Bob Cook ◽  
Karine D'Amore ◽  
Alberto Diaz ◽  
Andres Bracho
Keyword(s):  
Oil Recovery ◽  
Dynamic Modelling ◽  
Oil Production ◽  
Simulation Modelling ◽  
Oil Field ◽  
Optimal Time ◽  
Successful Implementation ◽  
Full Field ◽  
Execution Phase ◽  
Reservoir Simulator

The Moonie onshore oil field discovered in 1961, was the first commercial oil discovery in Australia. The field was purchased by Bridgeport Energy Limited (BEL) from Santos in late 2015. An Australian first initiative by BEL is to enhance oil production from the field using tertiary recovery CO2 miscible flood to maximise field oil recovery. The process involves an evaluation of well injection strategies for a miscible displacement process using reservoir simulation modelling. In addition, the project jointly addresses community concerns regarding the rise in greenhouse gas emissions by sourcing 60000–120000 tonnes/annum of CO2 from a nearby power station and/or an ethanol plant. Justified by laboratory experiments and reservoir compositional simulations, BEL’s project timeline to implement a CO2-enhanced oil recovery (EOR) pilot could start from 2020 followed by a 2–3-year full field oil production acceleration project if additional CO2 can be sourced. Based on incremental recovery and operational consideration, an injection well in the southern end of the field surrounded by six existing producers has been selected as a pilot flood. Positive indicative economics are achieved by the efficient displacement with CO2 of 8000 scf/bbl of incremental oil. Full field dynamic modelling predicts a further 8% oil recovery factor by injecting 60 Bcf of CO2 over five years, which could store in excess of three million tonnes of CO2. For the pilot, more than 90% of the injected CO2 will remain in the Precipice sandstone reservoir. However, the efficiency and viability of a CO2-EOR project is subject to successful implementation of the miscibility modelling, logistics and injection strategy and uncertainty quantification. To propel the project into the execution phase a fast-multiphase reservoir simulator has been implemented to complete a probabilistic range of results in optimal time.

Natural Dumpflood in Malaysia Succeeds as Low-Cost Offshore Oil-Recovery Method

2021 ◽  
Vol 73 (01) ◽  
pp. 51-52
Author(s):  
Judy Feder
Keyword(s):  
Oil Recovery ◽  
Low Cost ◽  
Oil Production ◽  
Thin Layers ◽  
Productivity Index ◽  
Asia Pacific ◽  
Successful Implementation ◽  
Solution Gas Drive ◽  
Gas Drive ◽  
Solution Gas

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196498, “First Natural Dumpflood in Malaysia: A Successful Breakthrough for Maximizing Oil Recovery in an Offshore Environment With Low-Cost Secondary Recovery,” by Muhammad Abdulhadi, SPE, Toan Van Tran, SPE, and Najmi Mansor, Dialog Group, et al., prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29–31 October. The paper has not been peer reviewed. The complete paper describes the first successful implementation of natural dumpflooding offshore Malaysia as a case study to provide insight into the value of using the approach to maximize oil recovery in a mature field, particularly in a low-margin business climate. Background Field B, located offshore Balingian province approximately 80 km northwest of Bintulu, has a water depth of 90 ft and is highly compartmentalized and faulted, with almost 100 faults present. The field features three subfields further divided into nine major fault compartments. Eight primary reservoirs exist, with more than 20 subreservoirs stacked atop one another with multiple drive mechanisms, including water drive, gas-cap drive, and solution gas drive. Several of these subreservoirs are thick sands between which communication exists through juxtapositions, shared gas caps, or aquifer. Other subreservoirs are isolated by thin layers of shale apparent in certain wells but absent in others. The high complexity of Field B requires any opportunity identified to be thoroughly evaluated and examined before execution. Field B is a moderately sized field discovered in 1976, with production commencing in 1984. During the 30 years of oil production, the field peaked at 30,000 B/D in 1990 and dipped to 3,000 B/D in late 1999. The facilities consist of four drilling platforms, a processing platform, and a compressor platform. A total of 48 wells were drilled in the field, with most wells completed as dual-string producers. The recovery factor (RF) of the reservoirs ranges from 10% for solution gas drive to 50% for strong water drive. The behaviors of these reservoirs are starkly different. The solution gas-drive reservoirs have poor-quality sand (less than 200 md), a low productivity index, limited sand thickness (less than 30 ft), limited sand connectivity, and sharp pressure decline after 2 to 3 years of production. The water-drive reservoirs, however, have good-quality sand (up to 5,000 md), a high productivity index, thick sand (greater than 40 ft), extensive sand connectivity, and limited pressure decline. The stark differences in the reservoirs’ behavior further complicate field management. The field currently is in late life, with recovery to date of 19% with an RF of 23%. Most of the water-drive reservoirs are already swept up to the crest, while the solution gas-drive reservoirs are depleted nearly to abandonment pressure. After 30 years of production, the total field water cut was at 80%, while oil production was approximately 5,000 B/D, signifying the diminishing economic life of the field.

New Surfactants and Cosolvents Increase Oil Recovery and Reduce Cost

SPE Journal ◽  
2018 ◽  
Vol 23 (06) ◽  
pp. 2202-2217 ◽  
Author(s):  
Karasinghe A. Nadeeka Upamali ◽  
Pathma Jith Liyanage ◽  
Sung Hyun Jang ◽  
Erin Shook ◽  
Upali P. Weerasooriya ◽  
...  
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Enhanced Recovery ◽  
Low Cost ◽  
Molecular Structures ◽  
Superior Performance ◽  
Equilibration Time ◽  
Crude Oil Prices ◽  
Wide Range ◽  
Reservoir Conditions

Summary Scientific understanding of how the molecular structures of surfactants and cosolvents affect microemulsion properties greatly speeds up the process of arriving at optimal chemical formulations for enhanced recovery of a specific crude oil. With the main emphasis on reducing the chemical cost of the formulations, novel surfactants and cosolvents have been developed and shown to have superior performance. We have synthesized and tested surfactants with different hydrophobe sizes and structures varying from ultrashort to large to satisfy a variety of crude-oil requirements over a wide range of reservoir conditions. The cosolvents and surfactants with ultrashort hydrophobes offer advantages such as short equilibration time for the microemulsion formation and lower microemulsion viscosity. Chemical formulations developed using these chemicals have shown excellent performance with very low cosolvent and surfactant retention in cores. Low retention means less chemicals can be used to recover each barrel of oil from the reservoir. These chemicals can be made commercially at low cost. Through use of these new developments, the chemical cost per barrel of oil is low enough to be economically viable, even at low crude-oil prices.

Successful Implementation of Polymer Flood in Aishwariya Field, Rajasthan, India - Concept to Full Field

2021 ◽  
Author(s):  
Aditya Kumar Singh ◽  
Pruthvi Raju Vegesna ◽  
Dhruva Prasad ◽  
Saideep Chandrashekar Kachodi ◽  
Sumit Lohiya ◽  
...  
Keyword(s):  
Water Injection ◽  
Oil Field ◽  
Surveillance Program ◽  
Successful Implementation ◽  
Reservoir Properties ◽  
Solution Quality ◽  
Full Field ◽  
Polymer Injection ◽  
Polymer Flood ◽  
Water Cut

Abstract The Aishwariya Oil Field located in Barmer Basin of Rajasthan India having STOIIP of ∼300 MMBBLS was initially developed with down-dip edge water injection. The main reservoir unit, Fatehgarh Formation, has excellent reservoir characteristics with porosities of 20-30% and permeability of 1 to 5 Darcys. The Fatehgarh Formation is subdivided into Lower Fatehgarh (LF) and Upper Fatehgarh (UF) Formations, of which LF sands are more homogenous and have slightly better reservoir properties. The oil has in-situ viscosity of 10-30 cP. Given its adverse waterflood mobility ratio, the importance of EOR was recognised very early. Initial screening studies identified that chemical EOR (polymer and ASP) was preferred choice of EOR process. Extensive lab studies and simulation work was conducted to develop the polymer flood concept. A polymer flood development plan was prepared targeting the LF sands of the field utilizing the lessons learnt from nearby Mangala Field polymer implementation project. The polymer flood in Aishwariya Field was implemented in two stages. In the first stage, a polymer injectivity test was conducted in 3 wells to establish the potential for polymer injection in these wells. The injection was extended to 3 more wells and continued for ∼4 years. Significant water cut drop was observed in nearby wells during this phase of polymer injection. In the next stage, polymer flooding was extended to the entire LF sands with drilling of 14 new infill wells and conversion of 8 existing wells to polymer injectors. A ∼14 km long pipeline was laid from the Mangala Central Polymer Facility to well pads in the field to cater to the requirement of 6-8 KBPD of ∼15000 ppm polymer mother solution. The philosophy of pre-production for extended periods was considered prior to start of polymer injection for all wells as it significantly improved injection (reduced skin) and conformance. Full field polymer flood project was implemented, and injection was ramped up to the planned 40-50 KBPD of polymerized water within a month owing to good injectivity and polymer solution quality. A detailed laboratory, well and reservoir surveillance program has been implemented and the desired wellhead viscosity of 25-30 cP has been achieved. Initial response shows significant increase in oil production rate and decrease in water-cut. This paper presents the polymer laboratory studies, initial long term injectivity test results, polymer flood development concept and planning, simulation studies and field implementation in LF Formation in Aishwariya Field.

scholarly journals Experimental study of the supercritical CO 2 diffusion coefficient in porous media under reservoir conditions

2019 ◽  
Vol 6 (6) ◽  
pp. 181902 ◽  
Author(s):  
Junchen Lv ◽  
Yuan Chi ◽  
Changzhong Zhao ◽  
Yi Zhang ◽  
Hailin Mu
Keyword(s):  
Porous Media ◽  
Diffusion Coefficient ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Capture And Storage ◽  
Elevated Pressure ◽  
Experimental Results ◽  
Saturated Porous Media ◽  
Reservoir Conditions ◽  
The Impact

Reliable measurement of the CO 2 diffusion coefficient in consolidated oil-saturated porous media is critical for the design and performance of CO 2 -enhanced oil recovery (EOR) and carbon capture and storage (CCS) projects. A thorough experimental investigation of the supercritical CO 2 diffusion in n -decane-saturated Berea cores with permeabilities of 50 and 100 mD was conducted in this study at elevated pressure (10–25 MPa) and temperature (333.15–373.15 K), which simulated actual reservoir conditions. The supercritical CO 2 diffusion coefficients in the Berea cores were calculated by a model appropriate for diffusion in porous media based on Fick's Law. The results show that the supercritical CO 2 diffusion coefficient increases as the pressure, temperature and permeability increase. The supercritical CO 2 diffusion coefficient first increases slowly at 10 MPa and then grows significantly with increasing pressure. The impact of the pressure decreases at elevated temperature. The effect of permeability remains steady despite the temperature change during the experiments. The effect of gas state and porous media on the supercritical CO 2 diffusion coefficient was further discussed by comparing the results of this study with previous study. Based on the experimental results, an empirical correlation for supercritical CO 2 diffusion coefficient in n -decane-saturated porous media was developed. The experimental results contribute to the study of supercritical CO 2 diffusion in compact porous media.

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