Annual Research Reports - Randy Seright - US Department of Energy

Third and final year of the conformance optimization project. X-ray CT imaging in Berea sandstone shows DPR occurs by gel trapping oil, forcing water through narrow pores and films. In oil-wet polyethylene, DPR occurs by a different mechanism — oil films and specific small pore pathways provide conduits unavailable to water. Gel extrusion pressure gradients and dehydration factors are similar at 20 to 80 degrees C, confirming limited temperature effect. In wider fractures (0.08 to 0.16 inches), gel washout can occur at lower pressure gradients than during placement. Software Version 2.0 adds support for gas wells with water production and SI units.

Second year of the conformance optimization project. The gel propagation mechanism in fractures is advanced: mobile gel forms wormholes through concentrated immobile dehydrated gel. The average leakoff rate follows ul = 0.05t^(-0.55) across fracture widths of 0.02 to 0.16 inches and injection fluxes of 129 to 66,200 ft/day. Pressure gradient during gel extrusion is insensitive to injection rate for a given fracture width. A field case involving a horizontal production well intersected by a fault is analyzed: downhole pressure measurements are used to infer fracture width and gel penetration depth. CMT imaging at Brookhaven National Laboratory begins to provide pore-scale evidence of gel distribution.

First year of a new conformance optimization project. Gel propagation through fractures is characterized: gel permeability correlates with polymer concentration to a power between -2.5 and -3.0. Higher-molecular-weight HPAM (Percol 338) achieves similar or better extrusion behavior at 2.5 times lower polymer and chromium concentrations — a significant cost advantage. Gelant treatment sizing software is updated to Version 1.07, improving low-water-cut handling and input modification. Field experience confirms that accurate current reservoir pressure data is essential for the sizing software. Gel rheology is characterized — elastic modulus greatly exceeds viscous modulus, consistent with ease of fracture extrusion. Disproportionate permeability reduction studies continue.

Final report of the three-year viscous oil polymer flooding project. Fractional flow calculations definitively show that residual oil saturation (Sor) reduction during polymer flooding significantly improves recovery efficiency for viscous oils, across all viscosity ranges and waterflood histories. The impact of Sor reduction diminishes with increasing reservoir heterogeneity. A new sulfonic tetra-polymer associative polymer (Mw 12 to 17 million) provides higher viscosity in porous media than HPAM 3830S but loses 31 to 45 percent of low-flux resistance factor after exposure to 235 psi/ft shear stress, compared to only 0 to 15 percent for standard HPAM. After 2500 psi/ft shear, the associative polymer’s advantage over HPAM essentially disappears. Polymer gels complement polymer flooding for sweep improvement in heterogeneous North Slope reservoirs.

Second year of the viscous oil polymer flooding project. Four questions are addressed. First, HPAM shear thinning in porous media can be observed at low salinity and high concentration but is slight or non-existent under practical EOR conditions — not a significant liability. Second, permeability reduction by polymers does not benefit vertical sweep efficiency, contrary to earlier claims; overall viscosity (resistance factor) is the key parameter. Third, polymer solution rheology (shear thinning vs. shear thickening vs. Newtonian) does not significantly affect sweep efficiency. Fourth, polymer flooding can be effective even after 5 pore volumes of prior waterflooding. Two biopolymers are evaluated: EX9719 xanthan provides 25 to 100 percent higher viscosity than standard xanthans with excellent filterability.

First year of a three-year project on polymer flooding for viscous oil recovery on Alaska’s North Slope. Fractional flow calculations and reservoir simulation (ECLIPSE, VIP, UTCHEM) assess polymer flooding of viscous oils (1 to 100,000 cp). For 1 pore volume of polymer injection in a two-layer free-crossflow system, oil recovery increases as the more-permeable layer becomes thicker. A preliminary economic analysis shows polymer flooding provides higher relative profit than waterflooding over a significant throughput range. Maximizing polymer solution injectivity is identified as the critical factor for economic viability. ECLIPSE simulator requires specific formatting to produce credible fractional flow predictions for the free-crossflow case.

Final report of the three-year project on improved fluid diversion techniques. Topics include gel properties in fractures and optimization of gel placement in fractured systems, investigation of why gels selectively reduce water permeability more than oil, comparison of microorganisms and particulates as blocking agents, and assessment of foams for superior placement properties. Gels remain the most technically mature and field-proven fluid diversion technology across the widest range of reservoir conditions. Microorganisms show less reliable and controllable placement than gels. Technology was transferred via SPE publications and industry reviews attended by 27 people from 13 organizations.

Second year of the fluid diversion comparison project. Foam placement is modeled using the limiting-capillary-pressure concept: foams are effective for gas coning reduction but have limited applicability for matrix water shutoff. Emulsions and particulate blocking agents are assessed and compared. Aluminum-citrate-HPAM gel propagation through porous rock is characterized as a Cr-free alternative. Gel properties in fractured systems are extended, including gel placement in unfractured anisotropic flow systems. DPR mechanism studies continue. The project supports a consortium of 10 oil companies.

First year of a new three-year project comparing gels with foams, emulsions, and particulates for fluid diversion, and identifying mechanisms of selective water permeability reduction. A survey of 1980-1992 field data and expert interviews at eight major oil companies establishes candidate selection criteria for injection and production wells. Theoretical analysis shows viscous forces dominate gravity during gelant injection into fractured wells. Preformed gels dramatically outperform in-situ-forming gelants at healing fractures and improving sweep. DPR is insensitive to core orientation, oil viscosity (1 to 31 cp), and system pressure (0 to 1500 psi). Two strategies to minimize fracture leakoff are identified: (1) time gelation before fracture entry, and (2) add particulates to the gelant.

Final report of the three-year water shutoff project. A predictive model is developed for areal gel front profiles in naturally fractured injection wells, incorporating yield-stress and gel dehydration. In fractures with effective widths of 0.006 to 0.04 inches, Cr(III)-acetate-HPAM gel is concentrated 20 to 40 times during extrusion, delaying propagation by the same factor. A minimum pressure gradient (yield stress) is required to extrude gel through fractures; a correlation is developed for this. No significant gel washout occurs after placement in fractures up to 0.4 inches wide during subsequent brine injection. A systematic philosophy for diagnosing water production problems is proposed, emphasizing root-cause identification before treatment design.

Second year of the water shutoff project, covering three advances. WOR (water/oil ratio) diagnostic plots are shown to be unreliable as standalone diagnostic tools — channeling and coning signatures easily overlap in simulation. An 11-step engineering procedure with GUI software provides a sound basis for sizing gelant treatments in hydraulically fractured production wells. For naturally fractured reservoirs, gel treatments are most promising when R-values (aligned to non-aligned fracture conductivity ratio) exceed 10, and when produced tracer concentrations exceed 30 percent of injected concentration. Tracer transit times are useful for estimating fracture conductivity but insensitive to R- and n-values.

First year of a new three-year project on improved water shutoff methods. A comprehensive review of gel placement concepts in both linear and radial flow systems establishes that acceptable gel placement is far easier in linear flow (fractures) than in radial flow (unfractured wells). In radial flow systems, zone isolation during gelant placement is essentially mandatory to protect oil-productive zones. Gel properties in fractures are characterized for Cr(III)-acetate-HPAM gels. Preformed gels are shown to have a placement advantage over water-like gelants for fracture length ratios below 3. Gel aging significantly increases fracture resistance factors during the first 24 hours. DPR mechanism studies continue. Project supported by DOE, BDM-Oklahoma, and 15 oil companies.

Final year of the three-year fluid diversion study. Four gel types are characterized: resorcinol-formaldehyde, colloidal silica, Cr3+(chloride)-xanthan, and Cr3+(acetate)-polyacrylamide. Chromium propagation is significantly faster with acetate counterions than with chloride — unbuffered Cr-Cl gelants likely cannot propagate through carbonate reservoirs. Strong gels reduce permeability to near-microdarcy values across all rock types. DPR is confirmed for monomer-based and polymer-based gels, but NOT for colloidal-silica gels. Tracer studies suggest strong gels encapsulate residual oil, rendering it inaccessible during subsequent oil flooding. WAG cycling causes gel breakdown, but DPR persists for most gel types. Guidelines are established for gel candidate selection in injection and production wells.

Second year of the gel fluid diversion study. Rock permeability and lithology effects on gel performance are characterized for Cr3+-xanthan, resorcinol-formaldehyde, and colloidal-silica gels. Disproportionate permeability reduction (DPR) is studied across different wettabilities: DPR is more pronounced in intermediate-wettability than strongly water-wet systems. All four gel types tested (resorcinol-formaldehyde, Cr-xanthan, Cr-polyacrylamide, colloidal silica) reduce water permeability more than CO2 permeability but experience breakdown during WAG cycles. Viscous gelants leak off from fractures into the matrix more than low-viscosity gelants. Design criteria for fracture applications: achieving a ratio of fracture penetration depth to matrix penetration depth greater than 10 times the matrix residual resistance factor is the target.

First year of a three-year study on fluid diversion with chemical gels in oil recovery. Objectives: identify gel diversion mechanisms and establish best-use guidelines. Resorcinol-formaldehyde gels at pH 9 achieve very high residual resistance factors (10^3 to 10^4); gelation is inhibited as pH drops below 7. Diffusion and dispersion cannot eliminate zone-isolation requirements in unfractured injection wells. Mathematical analysis shows gelants penetrate all open zones in both injection and production wells. Disproportionate permeability reduction — water permeability reduced more than oil permeability — is identified as critical for production well applications. Preformed gels outperform in-situ-forming gelants at healing fractures and improving sweep.

Second year of the conformance improvement project. X-ray CT data from previous work is re-analyzed using indicator kriging fluid segmentation, addressing critic concerns about pore size distributions. Core findings are confirmed and refined. A field gel treatment in an Arbuckle production well is analyzed, demonstrating laboratory-to-field translation of gel permeability reduction predictions. DPR in fractures is quantified: water/oil permeability ratios exceeding 89 are measured for fracture-resident gels. Partially formed gels and gels with mixed-molecular-weight polymers in fractures are characterized. Gel volume reduction in oil-wet porous polyethylene is driven by a dehydration mechanism rather than a gel-ripping mechanism.

First year of a new conformance improvement project. Gel extrusion and washout are characterized: in narrow fractures (1 mm or less), washout pressure gradient equals placement pressure gradient; in wider fractures (greater than 2 mm), washout can occur at significantly lower pressure gradients. A secondary gelation concept — gel crosslinks twice, first before fracture entry and then after placement — shows considerable promise. Gels in fractures (not just porous rock) can provide significant DPR. Casing pinhole leak plugging with Cr(III)-acetate-HPAM gel is demonstrated to be feasible at pressure gradients up to 3000 psi/ft. AquaCon adsorption-based polymer shows high variability in DPR performance.

Second year of the aperture-tolerant project, covering five topics: DPR optimization with strong pore-filling gels; RPM/DPR treatment guidelines for production wells; correlation of gel rheology with fracture extrusion behavior; sweep improvement options for Daqing Oil Field; and assessment of colloidal dispersion gels (CDGs) and foams. Strong pore-filling gels overcome three key DPR limitations of weak gels. RPM/DPR treatments are applicable to a narrow range of well conditions. The pressure gradient for gel extrusion varies inversely with the square of fracture width — linked to mobile gel wormhole width being much narrower than total fracture width. CDGs provide no significant sweep improvement beyond a standard polymer flood in the Daqing system studied.

First year of the aperture-tolerant channeling reduction project. Simulation studies assess optimal gel plug placement in fractured reservoirs under four well-fracture scenarios. For fracture widths of 0.25 mm or less in 100-md rock, channeling is not a problem. For wider fractures, at least 10 percent (ideally more than 20 percent) of the fracture must be plugged, centered, to significantly improve sweep. Near-wellbore plugs alone reduce channeling rates but do not improve matrix sweep. Low-concentration gels (0.2 to 0.25 percent HPAM) can plug 0.1-mm fractures but fail for 0.5-mm or wider fractures. Strong pore-filling gels consistently reduce water permeability to about 0.24 md regardless of initial permeability (120 to 6500 md).