Reservoir Description for a Surfactant/ Polymer Pilot in a Fractured, Oil-Wet Reservoir - North Burbank Unit Tract 97

Trantham, J.C.; Threlkeld, C.B.; Patterson, H.L.

doi:10.2118/8432-pa

Cited by 31 publications

(8 citation statements)

References 4 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Of course, the key concerns when injecting above the parting pressure are to not allow fractures to extend so far and in a direction that causes severe channeling, and to not allow them to extend out of zone. If these concerns can be mitigated, under the proper circumstances, injection above the parting pressure can significantly (1) increase polymer-solution injectivity and fluid throughput for the reservoir pattern, (2) reduce the risk of mechanical degradation for polyacrylamide solutions, and (3) increase pattern sweep efficiency (Trantham et al 1980;Wang et al 2008a;Seright et al 2009). Using both field data and theoretical analyses, these facts have been demonstrated at the Daqing oil field in China, where the world's largest polymer flood is in operation (Wang et al 2008a).…”

Section: Injectivity Considerationsmentioning

confidence: 99%

A Comparison of Polymer Flooding With In-Depth Profile Modification

Seright

Zhang

Akanni

et al. 2012

Journal of Canadian Petroleum Technology

View full text Add to dashboard Cite

For stratified reservoirs with free crossflow and where fractures do not cause severe channeling, improved sweep is often needed after water breakthrough. For moderately viscous oils, polymer flooding is an option for this type of reservoir. However, in recent years, an in-depth profile-modification method has been commercialized in which a block is placed in the high-permeability zone(s). This sophisticated idea requires that (1) the blocking agent have a low viscosity (ideally a unit-mobility displacement) during placement, that (2) the rear of the blocking-agent bank in the high-permeability zone(s) outrun the front of the blockingagent bank in adjacent less-permeable zones, and that (3) an effective block to flow form at the appropriate location in the high-permeability zone(s). Achieving these objectives is challenging but has been accomplished in at least one field test. This paper investigates when this in-depth profile-modification process is a superior choice over conventional polymer flooding.Using simulation and analytical studies, we examined oilrecovery efficiency for the two processes as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer-solution viscosity, (5) polymer-or blocking-agent-bank size, and (6) relative costs for polymer vs. blocking agent. The results reveal that in-depth profile modification is most appropriate for high permeability contrasts (e.g., 10:1), high thickness ratios (e.g., less-permeable zones being 10 times thicker than high-permeability zones), and relatively low oil viscosities. Because of the high cost of the blocking agent relative to conventional polymers, economics favours small blocking-agent-bank sizes (e.g., 5% of the pore volume in the high-permeability layer). Even though short-term economics may favour in-depth profile modification, ultimate recovery may be considerably less than from a traditional polymer flood.

show abstract

Section: Injectivity Considerationsmentioning

confidence: 99%

A Comparison of Polymer Flooding With In-Depth Profile Modification

Seright

Zhang

Akanni

et al. 2012

Journal of Canadian Petroleum Technology

View full text Add to dashboard Cite

show abstract

“…Of course, the key concerns when injecting above the parting pressure are to not allow fractures to (1) extend so far and in a direction that causes severe channeling and (2) extend out of zone. If these concerns can be mitigated, under the proper circumstances, injection above the parting pressure can significantly (1) increase polymer solution injectivity and fluid throughput for the reservoir pattern, (2) reduce the risk of mechanical degradation for polyacrylamide solutions, and (3) increase pattern sweep efficiency (Trantham et al 1980, Wang et al 2008a). Using both field data and theoretical analyses, these facts have been demonstrated at the Daqing Oilfield in China, where the world's largest polymer flood is in operation (Wang et al 2008a).…”

Section: Injectivity Considerationsmentioning

confidence: 99%

Use of Polymers to Recover Viscous Oil From Unconventional Reservoirs

Seright¹

2011

View full text Add to dashboard Cite

“…The presence of a fracture in a well can mitigate mechanical degradation. 133 Fractures provide a dramatic increase in flow area at the injection sand face, thus decreasing the velocity of the polymer solution at this important constriction, and thereby reducing mechanical degradation. Also, the presence of fractures in wells can significantly increase well injectivity and productivity indexes.…”

Section: Mitigating Polymer Degradationmentioning

confidence: 99%

Aperture-Tolerant, Chemical-Based Methods to Reduce Channeling

Seright¹

2007

View full text Add to dashboard Cite

DEDICATIONThis report is dedicated to Dr. Jerry Casteel, who recently retired after many years of government service. During his time with the DOE's National Petroleum Technology Office, Jerry consistently played an extremely constructive part in overseeing our research. While our government is often criticized for wasteful spending and flighty funding of ill-considered projects, Jerry was a great role model, illustrating the very best of our public servants. Being highly competent (both technically and managerially), he provided a voice of moderation and charted a steady long-term course for solving some of the nation's most difficult energy problems. We will miss his insights, his vision, his dedication to advancing petroleum engineering, and his friendship.iii ABSTRACT This final technical progress report describes work performed from October 1, 2004, through May 16, 2007, for the project, "Aperture-Tolerant, Chemical-Based Methods to Reduce Channeling."We explored the potential of pore-filling gels for reducing excess water production from both fractured and unfractured production wells. Several gel formulations were identified that met the requirements-i.e., providing water residual resistance factors greater than 2,000 and ultimate oil residual resistance factors (F rro ) of 2 or less. Significant oil throughput was required to achieve low F rro values, suggesting that gelant penetration into porous rock must be small (a few feet or less) for existing pore-filling gels to provide effective disproportionate permeability reduction. Compared with adsorbed polymers and weak gels, strong pore-filling gels can provide greater reliability and behavior that is insensitive to the initial rock permeability.Guidance is provided on where relative-permeabiliy-modification/disproportionate-permeabilityreduction treatments can be successfully applied for use in either oil or gas production wells. When properly designed and executed, these treatments can be successfully applied to a limited range of oilfield excessive-water-production problems.We examined whether gel rheology can explain behavior during extrusion through fractures. The rheology behavior of the gels tested showed a strong parallel to the results obtained from previous gel extrusion experiments. However, for a given aperture (fracture width or plate-plate separation), the pressure gradients measured during the gel extrusion experiments were much higher than anticipated from rheology measurements. Extensive experiments established that wall slip and first normal stress difference were not responsible for the pressure gradient discrepancy. To explain the discrepancy, we noted that the aperture for gel flow (for mobile gel wormholing through concentrated immobile gel within the fracture) was much narrower than the width of the fracture.The potential of various approaches were investigated for improving sweep in parts of the Daqing Oil Field that have been EOR targets. Possibilities included (1) gel treatments that are directed at channeling through fractures,...

show abstract

Reservoir Description for a Surfactant/ Polymer Pilot in a Fractured, Oil-Wet Reservoir - North Burbank Unit Tract 97

Abstract: ~ 1648 , 55 J " J " J 59 J 60 J 61 J

Cited by 31 publications

References 4 publications

A Comparison of Polymer Flooding With In-Depth Profile Modification

A Comparison of Polymer Flooding With In-Depth Profile Modification

Use of Polymers to Recover Viscous Oil From Unconventional Reservoirs

Aperture-Tolerant, Chemical-Based Methods to Reduce Channeling

Contact Info

Product

Resources

About