Exploring the Upper Limit of Oil Viscosity for Polymer Flood in Heavy Oil

2018 ◽  
Author(s):  
Eric Delamaide
Keyword(s):  
Heavy Oil ◽  
Oil Viscosity ◽  
Upper Limit ◽  
Polymer Flood

Heavy-Oil Recovery by Combined Hot Water and Alkali/Cosolvent/Polymer Flooding

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 74-86 ◽  
Author(s):  
M.. Tagavifar ◽  
R.. Fortenberry ◽  
E.. de Rouffignac ◽  
K.. Sepehrnoori ◽  
G. A. Pope
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Field ◽  
Hot Water ◽  
Mobility Control ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Polymer Flood ◽  
Low Interfacial Tension ◽  
Combined Strategy

Summary A hybrid process is developed and optimized for heavy-oil recovery that combines moderate reservoir heating and chemical enhanced oil recovery in the form of alkali/cosolvent/polymer flood. The process is simulated by use of a model derived from existing laboratory and pilot data of a 5,000-cp heavy-oil field. It is found that hot waterflooding is efficient in heating the reservoir only when high early injectivity is achievable. This may not be the case if incipient fluid injectivity is low and/or long, continuous, horizontal shale baffles are present. To remedy the former, an electrical-preheating period is devised, whereas switching to a horizontal flood could overcome the latter. Once the reservoir temperature is raised sufficiently, a moderately unstable alkali/cosolvent/polymer flood is capable of mobilizing and displacing oil. A best combined strategy for efficient reservoir heating, high oil recovery, and cost effectiveness is found to involve reducing the oil viscosity to values of approximately 300–500 cp and combining a degree of mobility control and low interfacial tension as recovery mechanisms.

scholarly journals Effect of initial water flooding on the performance of polymer flooding for heavy oil production

2020 ◽  
Vol 75 ◽  
pp. 19 ◽  
Author(s):  
Clement Fabbri ◽  
Romain de-Loubens ◽  
Arne Skauge ◽  
Gerald Hamon ◽  
Marcel Bourgeois
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
History Matching ◽  
Oil Production ◽  
Water Flooding ◽  
Relative Permeabilities ◽  
Oil Viscosity ◽  
Initial Water ◽  
Polymer Injection ◽  
Polymer Flood

In the domain of heavy to extra heavy oil production, viscous polymer may be injected after water injection (tertiary mode), or as an alternative (secondary mode) to improve the sweep efficiency and increase oil recovery. To prepare field implementation, nine polymer injection experiments in heavy oil have been performed at core scale, to assess key modelling parameters in both situations. Among this consistent set of experiments, two have been performed on reconstituted cylindrical sandpacks in field-like conditions, and seven on consolidated Bentheimer sandstone in laboratory conditions. All experiments target the same oil viscosity, between 2000 cP and 7000 cP, and the viscosity of Partially Hydrolyzed Polyacrylamide solutions (HPAM 3630) ranges from 60 cP to 80 cP. Water and polymer front propagation are studied using X-ray and tracer measurements. The new experimental results presented here for water flood and polymer flood experiments are compared with experiments described in previous papers. The effects of geometry, viscosity ratio, injection sequence on recoveries, and history match parameters are investigated. Relative permeabilities of the water flood experiment are in line with previous experiments in linear geometry. Initial water floods led to recoveries of 15–30% after one Pore Volume Injected (PVI), a variation influenced by boundary conditions, viscosity, and velocities. The secondary polymer flood in consolidated sandstone confirms less stable displacement than tertiary floods in same conditions. Comparison of secondary and tertiary polymer floods history matching parameters suggests two mechanisms. First, hysteresis effect during oil bank mobilization stabilizes the tertiary polymer front; secondly, the propagation of polymer at higher oil saturation leads to lower adsorption during secondary experiment, generating a lower Residual Resistance Factor (RRF), close to unity. Finally, this paper discusses the use of the relative permeabilities and polymer properties estimated using Darcy equation for field simulation, depending on water distribution at polymer injection start-up.

Pelican Lake: Learning From the Largest Polymer Flood Expansion in a Heavy Oil Field

2021 ◽  
Author(s):  
Delamaide Eric
Keyword(s):  
Heavy Oil ◽  
Large Scale ◽  
Horizontal Wells ◽  
Oil Field ◽  
Oil Viscosity ◽  
Polymer Injection ◽  
Polymer Flood ◽  
Chemical Eor ◽  
Significant Addition

Abstract Polymer has been injected continuously since 2005-06 in the Pelican Lake field in Canada, starting with a pilot rapidly followed by an expansion. At some point, 900 horizontal wells were injecting 300,000 bbl/d of polymer solution and oil production related to polymer injection reached 65,000 bopd. As a result, the Pelican Lake polymer flood is the largest polymer flood in heavy oil in the world and the largest polymer flood using horizontal wells. Although some papers have already been devoted to the initial polymer flood pilots, very little has been published on the expansion of the polymer flood and this is what this paper will focus on. The paper will describe the various phases of the polymer flood expansion and their respective performances as well as discuss the specific challenges in the field including strong variations in oil viscosity (from 800 to over 10,000 cp), how irregular legacy well patterns were dealt with, and how primary, secondary and tertiary polymer injection compare. It will also show the performances of polymer injection in combination with multi-lateral wells and touch upon the surface issues including the facilities. The availability of field and production data (which are public in Canada) combined with the variability in the field properties provide us with a wealth of data to better understand the performances of polymer flooding in heavy oil. This case study will benefit engineers and companies that are interested in polymer flood, in particular in heavy oil. The paper will be a significant addition to the literature where few large scale chemical EOR expansions are described.

scholarly journals Designing pressure build-up test on heavy oil well by alternating oil viscosity

2019 ◽  
Vol 1402 ◽  
pp. 022029 ◽  
Author(s):  
M T Fathaddin ◽  
R H K Oetomo ◽  
N Hisanah
Keyword(s):  
Heavy Oil ◽  
Oil Well ◽  
Oil Viscosity

Resin from Liaohe Heavy Oil: Molecular Structure, Aggregation Behavior, and Effect on Oil Viscosity

2017 ◽  
Vol 32 (1) ◽  
pp. 306-313 ◽  
Author(s):  
Tao Li ◽  
Jun Xu ◽  
Run Zou ◽  
Hao Feng ◽  
Li Li ◽  
...  
Keyword(s):  
Molecular Structure ◽  
Heavy Oil ◽  
Aggregation Behavior ◽  
Oil Viscosity

Laboratory Support of Heavy-Oil Polymer Flood Project

2016 ◽  
Author(s):  
Rashid S. Al-Maamari ◽  
Abdulaziz Al-Hashmi ◽  
Nasser Al-Azri ◽  
Omaira Al-Riyami ◽  
Rifaat Al-Mjeni ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Polymer Flood

Study employment perspectives of cavitation technolo- gies in pipeline transportation

2020 ◽  
pp. 41-46
Author(s):  
S.T. Aliyev ◽  
Keyword(s):  
Heavy Oil ◽  
Hydrodynamic Cavitation ◽  
Pipeline Transportation ◽  
Oil Viscosity ◽  
Operation Mechanism ◽  
Cavitation Process ◽  
Alternative Method

The paper explores the aspects negatively affecting the pipeline transportation of heavy oil and reviews the implementation possibility of cavitation processes as an alternative method of solving occurring problems. Based on the laboratory researches of abnormal oil from Azerbaijan fields, the parameters and technical upgrade of heavy oil in the system of hydrodynamic cavitation have been studied. Moreover, as a result of carried out experiments, the operation mechanism of cavitation process during reduction of heavy oil viscosity has been described and the implementation prospect of this technology in commercial scales analyzed as well.

Rich-Gas Condensate Huff and Puff Process in High-Volume, Watered-Out, and Highly Viscous Heavy Oil Wells, Case Study in Iraq

2021 ◽  
Author(s):  
Xueqing Tang ◽  
Ruifeng Wang ◽  
Zhongliang Cheng ◽  
Hui Lu
Keyword(s):  
High Pressure ◽  
Heavy Oil ◽  
Oil Quality ◽  
Oil Wells ◽  
Gas Condensate ◽  
Oil Viscosity ◽  
Foamy Oil ◽  
Artificial Lift ◽  
Water Coning ◽  
The Dead

Abstract Halfaya field in Iraq contains multiple vertically stacked oil and gas accumulations. The major oil horizons at depth of over 10,000 ft are under primary development. The main technical challenges include downdip heavy oil wells (as low as 14.56 °API) became watered-out and ceased flow due to depleted formation pressure. Heavy crude, with surface viscosities of above 10,000 cp, was too viscous to lift inefficiently. The operator applied high-pressure rich-gas/condensate to re-pressurize the dead wells and resumed production. The technical highlights are below: Laboratory studies confirmed that after condensate (45-52ºAPI) mixed with heavy oil, blended oil viscosity can cut by up to 90%; foamy oil formed to ease its flow to the surface during huff-n-puff process.In-situ gas/condensate injection and gas/condensate-lift can be applied in oil wells penetrating both upper high-pressure rich-gas/condensate zones and lower oil zones. High-pressure gas/condensate injected the oil zone, soaked, and then oil flowed from the annulus to allow large-volume well stream flow with minimal pressure drop. Gas/condensate from upper zones can lift the well stream, without additional artificial lift installation.Injection pressure and gas/condensate rate were optimized through optimal perforation interval and shot density to develop more condensate, e.g. initial condensate rate of 1,000 BOPD, for dilution of heavy oil.For multilateral wells, with several drain holes placed toward the bottom of producing interval, operating under gravity drainage or water coning, if longer injection and soaking process (e.g., 2 to 4 weeks), is adopted to broaden the diluted zone in heavy oil horizon, then additional recovery under better gravity-stabilized vertical (downward) drive and limited water coning can be achieved. Field data illustrate that this process can revive the dead wells, well production achieved approximately 3,000 BOPD under flowing wellhead pressure of 800 to 900 psig, with oil gain of over 3-fold compared with previous oil rate; water cut reduction from 30% to zero; better blended oil quality handled to medium crude; and saving artificial-lift cost. This process may be widely applied in the similar hydrocarbon reservoirs as a cost-effective technology in Middle East.

Sign in / Sign up

Export Citation Format

Share Document