Presentation on theme: "Study of Imbibition Mechanisms in the Naturally Fractured Spraberry Trend Area Yan Fidra Petroleum and Chemical Engineering Department New Mexico Institute."— Presentation transcript:
Study of Imbibition Mechanisms in the Naturally Fractured Spraberry Trend Area Yan Fidra Petroleum and Chemical Engineering Department New Mexico Institute of Mining and Technology
Outline Introduction –Problem statement –Literature review –Objectives –Overview of the study Laboratory Experiments Modeling Conclusions Recommendations
Problem Statement Lack in understanding of upscaling laboratory imbibition experiments to field dimensions - Low rock permeability that represent real thing - Static and dynamic process - Reservoir conditions Wetting behavior
Literature Review rock characteristics (Mattax and Kyte, 1962; Torsaeter, 1984; Thomas 1984; Hamon and Vidal, 1988) fluid properties (Iffly et al., 1972; Cuiec et al., 1990; Keijzer and De Vries, 1990; Ghedan and Poetmann, 1990; Schechter et al., 1991; Babadagli, 1995; Al-Lawati and Saleh, 1996) low permeability of Chalk reservoir (Torsaeter, 1984; Bourbiaux and Kalaydjian, 1990; Cuiec et al., 1990) wettability (Anderson, 1986; Hirasaki, et al, 1990; Zhou et al., 1995; Buckley, et al, 1995) aging time and temperature and initial water saturations (Zhou et al., 1993; Jadhunandan and Morrow, 1991) scaling of imbibition data (Mattax and Kyte, 1962; Lefebvre du Prey, 1978; Ma, 1995; Zhang et al, 1996)
Objectives To investigate wettability of Spraberry Trend Area at reservoir conditions. To upscale the laboratory imbibition results to field-scale dimensions. To investigate the contribution of the capillary imbibition mechanism to waterflood recovery. To determine the critical water injection rate during dynamic imbibition.
Overview of the Study Static imbibition Dynamic imbibition Field dimension Determine rock wettability Upscaling Determine laboratory critical injection rate Fracture Capillary Number Scaling equations Capillary pressure curve
Outline Introduction Laboratory Experiments –Static Imbibition Tests Verify the effect of P & T on recovery mechanisms Determine rock wettability index –Dynamic Imbibition Tests Investigate the effect of injection rate on recovery mechanism Determine critical injection rate Modeling Conclusions Recommendations
Porous Media Fluids Crude Oil Synthetic Reservoir Brine (TDS = 130,196 ppm) Berea sandstone Low permeability Spraberry rock Materials
Schematic Diagram of the Static Imbibition Process in Laboratory core oil water Imbibition model with one end closed 1.5” X 2.5 - 3.0” Core Synthetic brine beaker 138 o F
Experimental Set-up for Imbibition Tests under HPHT BV NV PR Graduated Cylinder Brine Tank High Pressure Imbibition Cell N 2 Bottle (2000 psi) Air Bath BV = Ball Valve NV = Needle Valve PR = Pressure Regulator Top View Inlet for creating tangential flow Side View core
Brine PumpOil Pump Air Bath Core holder Confining pressure gauge Graduated cylinder Oil tankBrine tank Flooding Apparatus
Effect of Pressure and Temperature on Static Imbibition Rate and Recovery using Berea Sandstone
138 o F 70 o F Effect of Temperature on Static Imbibition Rate and Recovery using Spraberry Reservoir Rock
Cleaning Spraberry core plugs Dean Stark Extraction Chloroform Displacement Drying (2 days) Evacuation (24 hours) Weight Evacuated Spraberry brine Measure brine density and viscosity Saturation of core samples Ionic equilibrium (3 days) Porosity calculation Brine permeability Recheck the porosity Oil viscosity, density and IFT measurements Oil flooding Establish Swi i Aging core samples in oil Aging time (days) 0 3 7 14 21 30 at reservoir temperature Aging time (days) 0 7 14 at reservoir temperature No aging time Imbibition tests (21 days) at reservoir temperature Imbibition tests (21 days) at reservoir temperature Imbibition tests (2 months) at ambient condition Brine displacement at room temperature Brine displacement at reservoir temperature Brine displacement at room temperature Results Experimental Procedures for determining WI using Spraberry Cores
Displacement A B Static imbibition Amott Wettability Index 0 1 Water-wet moreless
Static imbibition A Oil Recovery Curves Obtained from Static Imbibition Experiments at Reservoir Temperature Spraberry cores
Displacement A B Staticimbibition Total recovery vs aging time shows that 7 days aging time is adequate to start the experiments Spraberry cores
Displacement A B Static imbibition Wettability index vs aging time for different experimental temperatures Spraberry cores
Dynamic Imbibition Experiments Schematic of displacement process Experimental apparatus Results
MATRIX BLOCK FRACTURE Water Oil + Water Oil saturated matrix Imbibed water Capillary imbibition Viscous flow Oil produced Schematic Representation of the Displacement Process in Fractured Porous Medium
Matrix Fracture Artificially fractured core Air Bath Core holder Brine tank Confining pressure gauge Graduated cylinder N 2 Tank (2000 psi) Ruska Pump Experimental Apparatus for Dynamic Imbibition Tests
Oil Recovery from Fractured Berea Cores during Water Injection using Different Injection Rates
Unfractured core Fractured core Oil Recovery from Fractured Spraberry Cores during Water Injection using Different Injection Rates
Injection rate versus oil-cut curve for Berea and Spraberry cores
Outline Introduction Laboratory Experiments Modeling –Static imbibition data Investigate Pc from matching of experimental data. Scale up of static imbibition data. –Dynamic imbibition data Obtain Pc curves from matching of experimental data. Scale up of dynamic imbibition data. Conclusions Recommendations
Modeling of Static Imbibition Numerical Analysis of Static Imbibition Data Scaling of static imbibition data Results
Matching between Laboratory Experiments and Numerical Solution Capillary Pressure Curve Obtained as a Result of Matching Experimental data Numerical Analysis of Static Imbibition Data
Scaling of Imbibition Data “ Concept of Imbibition Flooding Process” ( Brownscombe, 1952 ) Water Matrix Fracture Invadedzone Oil production Oil production by water imbibition water oil Capillary force fracturematrix Matrix fracture fluid exchange mechanism Viscous force To investigate the contribution of a static imbibition process to waterflood recovery
Imbibition A Complete Oil Recovery Curves Obtained from Imbibition Experiments Spraberry cores No aging
Oil Recovery Curves in Terms of Dimensionless Variables
L s = 3.79 ft h = 10 ft Recovery Profile Upper Spraberry 1 U Formation (Shackleford-138) 1U
Effect of Matrix Permeability and Fracture Spacing on Oil Recovery
Modeling of Dynamic Imbibition Data Numerical analysis of dynamic imbibition data to obtain capillary curves. Concept of fracture capillary number. Upscaling of dynamic imbibition data to determine critical water injection rate.
Matching Between Experimental Data and Numerical Solution Berea Core Spraberry Core Cumulative water production vs. time Cumulative oil production vs. time Cumulative water production vs. time Cumulative oil production vs. time
P c Curves Obtained as Result of Matching Experiment Data Spraberry core Berea core P c from Numerical Model and Laboratory Experiment
Field Units : Lab Units : Fracture Capillary Number AmAm w dz AfAf Capillary force ( cos A m ) Viscous force (v w A f ) h
Conclusions Wettability Determination –Performing the imbibition tests at reservoir temperature and displacement tests at room temperature indicate that WI is 0.3 to 0.4. –Performing both imbibition and displacement tests at the same temperature (i.e., reservoir temperature or at room temperature) lowers the WI in the range of 0.20 to 0.25; thus, the temperatures during the experimental sequence affect wettability index determination. –Comprehensive experimental data clearly demonstrates that Spraberry reservoir rock is a very weakly water-wet system.
Conclusions (cont’d) Static Imbibition –Effect of pressure is much less important than the effect of temperature on imbibition rate and recovery. –Performing the imbibition tests at higher temperature results in faster imbibition rate and higher recovery due to change in mobility of fluids, expansion of oil, and change in IFT. –The final recovery due to imbibition using Spraberry cores varies from 10% to 15% of IOIP, depending on aging time.
Conclusions (cont’d) Scaling of static imbibition data –The contribution of the imbibition mechanism to oil recovery is up to 13% IOIP, depending on rock properties and wettability. –Degree of heterogeneity in the matrix and natural fracture system controls the efficiency of Spraberry waterflood performance.
Conclusions (cont’d) Dynamic Imbibition –As the flow rate increases, contact time between matrix and fluid in fracture decreases causing less effective capillary imbibition. –The capillary pressure curve obtained from dynamic imbibition experiments is higher that of the static imbibition experiments due to viscous forces during the dynamic process.
The limiting value of fracture capillary number for an efficient displacement process in this study was found to be 0.0001 and 0.00028 for Berea and Spraberry cores, respectively. Beyond this range, the displacement process is inefficient due to high water-cut. Conclusions (cont’d)
Necessary to correlate the static and dynamic tests in order to achieve proper upscaling. The capillary pressure curve obtained from dynamic imbibition experiments using artificially fractured core can be used as input data in naturally fractured reservoir simulations instead of using mercury injection capillary pressure curves.
Acknowledgement I would like to express my sincere appreciation and gratitude to my advisor Dr. David S. Schechter and My committee members Dr. Robert L. Lee, Dr. H.Y. Chen and Dr. Donald Weinkauf for their advice and time spent on this thesis. To PRRC for the financial support through research assistantship grant. To my fellow students and the entire staff of the PRRC for their kindness and assistance.