Abstract:
Heavy oil reservoirs under consideration for polymer flooding typically contain greater
than 85% of the original oil in place (OOIP) after primary recovery and waterflooding.
Many of these fields are operated at high producing water/oil ratios (WORs) only
marginally above their economic limit due to additional production, handling, and
treatment expenses that can average $3/m3 of water. Depending on timing of
implementation, operators could achieve very high incremental recoveries approaching
20% OOIP and beyond, as suggested by the experiments conducted in this work.
The main premise behind this thesis study is to develop fundamental knowledge
of the rheology and flow behavior of polymeric fluids that is essential in creating a
detailed screening protocol. The evaluation of these critical parameters is based upon the
following: 1) fundamental rheological measurements of non-Newtonian polymeric
fluids; 2) injectivity sandpack floods to determine in-situ dynamic viscosities through the
concept of Resistance Factor, Fr; 3) immiscible displacement of heavy oil by water and
polymers to determine microscopic displacement efficiency; 4) larger-scale, 3D physical
modeling of the polymer flood process; and, lastly 5) numerical simulation.
A specialized rheometer was used to determine the viscoelastic properties of both
hydrolyzed polyacrylamides (HPAM) and hydrophobically associating polyacrylamides
(HAP) used in heavy enhanced oil recovery (EOR) processes. The rheometric analyses
indicated that improved resistance to flow due to elastic phenomenon were observed as a
function of the polymer type, concentration, molecular weight, degree of hydrophobicity;
however, solution shear history, salinity and temperature were found to have a slightly
negative effect. Compared to traditional HPAMs, a medium density HAP showed an earlier onset of elastically-dominated flow as determined by its increased elasticity,
characteristic relaxation time and Weissenberg number.
Sandpack flood results suggested that HAP polymers can exhibit lower Fr values at
higher injection rate (easier to inject near wellbore) and higher Fr values at in-situ,
reservoir flow rates, i.e. 0.3 m/d (1 ft/d). Immiscible displacement tests from 1D sandpacks
showed accelerated recovery from floods employing HAP polymers over HPAM polymers
and incremental polymer flood recovery varied from 13.9 %OOIP (low concentration
HPAM) to as high as 43 %OOIP (high concentration HAP).
A 3D physical model was designed and fabricated to replicate the heavy oil
recovery process. The data sets generated were representative of some of the average field
recoveries from vertically-developed inverted 5-spot or staggered line drive heavy oil
recovery schemes. The 3D model also provided unique insight into the visual renderings
of the improved polymer over water displacement of heavy oil during the excavation of the
model. The displacement was quite chaotic and fractal during waterflood (RF = 19.5
%OOIP after 0.78 PVs); while the subsequent polymer flood greatly expanded the
floodable zones contacted by polymer, increasing the heavy oil recovery by an incremental
34.0 %OOIP (after 0.66 PVs). An additional 7.1 %OOIP was recovered during the 0.70
PVs of extended waterflood; however, much of this was due to displacement by polymer
solution still remaining in the model, as oil recovery diminished greatly after dye
breakthrough. The simulation of both 1D and 3D experimental physical models indicates
that a unique solution to recovery and pressure behaviour could be found using CMG’s
CMOST module by using experimental and chemical data inputs. Therefore the processes
were satisfactorily modeled numerically.
Description:
A Thesis Submitted to the Faculty of Graduate Studies and Research in Partial Fulfillment of the Requirements for the Degree of Doctor of Philosophy in Petroleum Systems Engineering, University of Regina. xvii, 260 p.