Total Dissolved Solids Removal From Water Produced During The In Situ Recovery Of Heavy Oil And Bitumen

1989 ◽  
Vol 28 (01) ◽  
Author(s):  
S. Kok ◽  
A. Zaidi ◽  
R. Solomon
Keyword(s):  
Heavy Oil ◽  
Total Dissolved Solids ◽  
Dissolved Solids ◽  
Solids Removal ◽  
In Situ Recovery

scholarly journals Numerical Analysis of the Source of Excessive Na+ and Cl- Species in Flowback Water From Hydraulically Fractured Shale Formations

SPE Journal ◽  
2016 ◽  
Vol 21 (05) ◽  
pp. 1477-1490 ◽  
Author(s):  
Maxian B. Seales ◽  
Robert Dilmore ◽  
Turgay Ertekin ◽  
John Yilin Wang
Keyword(s):  
Total Dissolved Solids ◽  
Particle Migration ◽  
Water Volume ◽  
Dissolved Solids ◽  
Flowback Water ◽  
Fully Implicit ◽  
Fracturing Process ◽  
Dissolution Model ◽  
Fracture Fluid

Summary Fracture fluid is composed of fresh water, proppant, and a small percentage of other additives, which support the hydraulic-fracturing process. Excluding situations in which flowback water is recycled and reused, the total dissolved solids in fracture fluid is limited to the fluid additives, such as potassium chloride (1 to 7 wt% KCL), which is used as a clay stabilizer to minimize clay swelling and clay-particle migration. However, the composition of recovered fluid, especially as it relates to the total dissolved solids (TDS), is always substantially different from the injected fracture fluid. The ability to predict flowback-water volume and composition is useful when planning for the management or reuse of this aqueous byproduct stream. In this work, an ion-transport and halite-dissolution model was coupled with a fully implicit, dual-porosity, numerical simulator to study the source of the excess solutes in flowback water and to predict the concentration of both Na+ and Cl− species seen in recovered water. The results showed that mixing alone, between the injected fracture fluid and concentrated in-situ formation brine, could not account for the substantial rise in TDS seen in flowback water. Instead, the results proved that halite dissolution is a major contributor to the change in TDS seen in fracture fluid during injection and recovery. Halite dissolution can account for as much as 81% of Cl− and 86.5% of Na+ species seen in 90-day flowback water; mixing, between the injected fracture fluid and in-situ concentrated brine, accounts for approximately 19% of Cl− and 13% of Na+.

Numerical Modelling Of Advanced In Situ Recovery Processes In Complex Heavy Oil & Bitumen Reservoirs

2005 ◽  
Author(s):  
Colin Charles Card ◽  
Jason Christopher Close ◽  
David Albert Collins ◽  
Peter H. Sammon ◽  
Thomas James Wheeler ◽  
...  
Keyword(s):  
Numerical Modelling ◽  
Heavy Oil ◽  
Recovery Processes ◽  
In Situ Recovery

A novel chemical additive for in-situ recovery of heavy oil using waterflooding process

2015 ◽  
Vol 135 ◽  
pp. 484-497 ◽  
Author(s):  
Omid Mohammadzadeh ◽  
Ioannis Chatzis ◽  
John P. Giesy
Keyword(s):  
Heavy Oil ◽  
Chemical Additive ◽  
In Situ Recovery

Numerical Modelling of Advanced In Situ Recovery Processes in Complex Heavy Oil and Bitumen Reservoirs

2005 ◽  
Author(s):  
C.C. Card ◽  
J.C. Close ◽  
D.A.C. Collins ◽  
P.H. Sammon ◽  
N.G. Fortson ◽  
...  
Keyword(s):  
Numerical Modelling ◽  
Heavy Oil ◽  
Recovery Processes ◽  
In Situ Recovery

Viscosity Measurement and Modeling for Mixtures of Athabasca Bitumen/n-Pentane at Temperatures Up to 200°C

SPE Journal ◽  
2014 ◽  
Vol 20 (02) ◽  
pp. 226-238 ◽  
Author(s):  
Hossein Nourozieh ◽  
Mohammad Kariznovi ◽  
Jalal Abedi
Keyword(s):  
Heavy Oil ◽  
Volume Fraction ◽  
Weight Fraction ◽  
Viscosity Reduction ◽  
Athabasca Bitumen ◽  
Recovery Processes ◽  
Correlation Models ◽  
In Situ Recovery ◽  
Recovery Methods

Summary The phase-behavior and thermophysical properties of bitumen/solvent systems are of crucial importance for heavy-oil and bitumen in-situ recovery methods. The viscosity reduction as a result of solvent dissolution and/or steam heating is the main recovery mechanism in the solvent-based bitumen-recovery processes. In this paper, the viscosity of bitumen, pentane, and their mixtures at different pentane weight fractions (0.05, 0.1, 0.2, 0.3, 0.4, and 0.5) are accurately measured. The measurements are conducted under conditions applicable for both in-situ recovery methods and the pipeline transportation of heavy oil. The experiments are taken with Athabasca bitumen at temperatures varying from ambient up to 200°C and at pressures up to 10 MPa. The data for the mixtures are evaluated with predictive schemes as well as with correlation models representing certain mixing rules proposed in the literature. The influences of pressure, temperature, and solvent weight fraction on the viscosity of mixtures are considered in the models and evaluated from the experimental data. The results indicated that the power-law model and the Cragoe model (Cragoe 1933) represent the data better than other models that use a volume-fraction basis.

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