SPE 141091

Single-well In-situ Measure of Oil Saturation Remaining in Carbonate after an EOR Chemical Flood John Edwards, Raghu Ramamoorthy, Ed Harrigan (Schlumberger), Maniesh Singh, Harry Soek, John Van Wunnik, Mohammed Al Yarabi, (Petroleum Development Oman), Rifaat Al Mjeni (Shell Technology Oman)

Copyright 2011, Middle East Oil and Gas Show and Conference This paper was prepared for presentation at the Middle East Oil and Gas Conference held in Bahrain, 25-28 September 2011. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright

Abstract

The MicroPilot* is a log-drill-inject-log sequence of operations designed to evaluate the improvement in oil recovery resulting from the addition of chemicals to the injected water. The fluid to be injected is transported downhole in a sample chamber and injected into the formation through a pencil sized drilled hole, with measurements of the resulting changes in saturation proximal to the well. This technique was first used during 2009 in Oman to perform an in-situ test of alkaline surfactant polymer in high porosity-permeability clean sandstone saturated in medium viscosity oil. This in-situ measurement is even more relevant for carbonates, as it eliminates the uncertainty associated with restoring mixed wettability in cores prior to laboratory enhanced oil recovery (EOR) floods. However executing a log-drill-inject-log sequence of operations in tight carbonates is more complex than clastics. The issues include small scale heterogeneity, presence of natural or induced micro-fractures, varying residual oil saturations, and the low permeability that requires injecting at pressures above the drilling fluid hydrostatic pressure. The operation and results of the first use of this EOR screening technology in carbonates is described in this paper in which an alkaline surfactant mixture (AS) was injected into a partially water swept 3mD permeability carbonate containing light oil. Aspects described include the mechanical process of drilling and injecting AS and the petrophysics of measuring changes of oil saturation at a small scale. The saturation changes are compared with other AS flood measurements in a neighboring well test using Single Well Chemical Tracer (SWCT) and cased hole logs. *Mark of Schlumberger Introduction The field in North Oman under study has been on production since 1976 and is at depths just over a 1000m. The field comprises low relief anticlinal domes with a common free water level. There are two reservoir intervals in the field, the Lower Shuaiba and the underlying Kharaib, both of which were deposited on a laterally extensive shallow water carbonate shelf. Both reservoirs have 25 - 29 PU porosity, permeability 1 - 10mD, oil gravity 37 API, and connate water salinity of 230,000ppm. The under-saturated oil is relatively light and has viscosities in the order of 0.8 cP. The goal is to demonstrate that chemical technology can produce economic incremental oil from a waterflood carbonate reservoir containing low viscous light oil. The chemical flood is screened in a phased manner (Stoll et al, 2010). This starts with interfacial tension reduction tests and phase behaviour experiments in the laboratory to find a suitable chemical to optimally mobilize residual oil to waterflood. This is followed by single well field trials using SWCT to back up the laboratory experiments (Deans et al, 2007), extensive wireline logging with thermal neutron decay and carbon/oxygen to confirm the SWCT results (Soek et al, 2011), and a MicroPilot* (Shyam et al, 2010). After a possible multi-well pilot phase involving a number of patterns, a large scale field implementation can be pursued.

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Job Design Objectives: A key input parameter for an EOR project is to assess what the Remaining Oil Saturation (ROS) is after the primary and secondary developments have been implemented. Several methods are available to assess the ROS, ranging from analogues, lab measurements, logging techniques to specialized coring procedures. However, of all the methods available, the SWCT and the MicroPilot* are the only single well in-situ measurements of an EOR flood, though at different resolution scales, and therefore provide an alternative assessment of ROS to core and analogue data. Open Hole Well Design: The drilling fluid should not contain surfactants that will alter the wettability of the invaded zone. The well inclination across the reservoir should be at least 10 and constant. This inclination is to facilitate natural orientation of the pads on the saturation logging tools to the low side of the hole. A constant inclination is preferable to minimize the likelihood of getting stuck with the Openhole Driller-Injector (OHDT) with sample chambers and the orientation device. This tool is 40m long and 5-in diameter at the chambers (Orban et al, 2009). Injection Depth Selection: Chemical EOR screening was attempted in both the Lower Shuaiba and the Kharaib reservoir. In preparation the density log was recorded at a slow speed with high resolution, and a high resolution laterolog array resistivity tool (HRLA) was used to improve the analysis of the mud filtrate invasion. A borehole electric image was recorded to identify natural fractures to be avoided when injecting, and to understand formation heterogeneity and hole size. A fracture-free high-porosity, relatively high-mobility zone was selected in both reservoirs, each with two potential injection points. The fluid mobility of these pre-selected injection points were then measured with a wireline formation tester. Fluid mobilities in adjacent wells indicated that anything above 2.5mD/cP was the most permeable formation to be expected. Oil Saturation Logs: It is preferable to have two independent methods of measuring the change in oil saturation resulting from the AS injection. These saturation measurements should be insensitive to or compensated for changes in water salinity, and be free of influence from the AS. This is necessary because four fluid salinities may be present; connate water 230,000 ppm, injection water 180,000 ppm, mud filtrate 127,000 ppm and alkaline 28,000 ppm, moreover the surfactant may change the wettability and water-space tortuosity that is numerically represented in the resistivity Archie equation by the n exponent. The measured volume of the logging tools must be smaller than the oil de-saturated zone in the center of the flood. The smallest dimension of the 3D flood in a reservoir with Kv/Kh = 0.2 will be the vertical height. Modeling of 20 liters of injected volume indicates that the vertical height of the swept zone will be 15cm. This dictates the required vertical resolution of the logging tools, which becomes a high resolution logging exercise. The Array Dielectric Tool (ADT) which directly measures the water volume has a vertical resolution of 2.5cm (Hizem et al. 2008) Fig 1. To derive water saturation from the ADT a total porosity measurement is required. The highest density resolution available from the three detector litho density (TLD) which is part of the platform express (PEX) is 5cm. This high resolution density is used to create a 5cm lithology and porosity log, which when combined with the ADT provides a 5cm saturation log. The ADT, TLD and micro cylindrically focused resistivity (MCFL) have their sensors mounted on pads, so in heterogeneous carbonate the logs should be recorded on the same side of the borehole for both the before and after logging passes. The TLD density pad of the PEX proved to be the most reliable tool orientation device. The ADT resolution of 2.5cm requires the logging pass to be recorded without any tool sticking. This movement is monitored with the tool acceleration sensors. The second saturation measurement that is independent of salinity and the Archie n exponent is the volumetric nuclear magnetic resonance (NMR) measurement that has a vertical resolution of 15.24 cm. The geometric shape of the NMR measured volume has the shape of a vertical cigar, 1-in diameter centered 1.1-in into the formation Fig 2. Saturation from NMR uses the fluids different diffusion properties when the oil has a viscosity close to water, because on the viscosity-relaxation axis the oil and water are indistinguishable. Diffusion measurements from the NMR 15.24 cm antenna are only possible when the tool is stationary. The duration of these stationary measurements is dictated by the signal to noise ratio (SNR), which is monitored in real-time. The stations are complete when the SNR reaches 20, which corresponds to an error in the oil and water volumes of 1.25 PU. In 29 PU rock this error corresponds to a saturation accuracy of 4%. Eleven stationary measurements were recorded every 7.62cm (3-in) across the two intervals selected for performing the MicroPilot*. This 76cm interval allows for repeated drilling and injection attempts if necessary Figs 3 - 4. Openhole DrillerTool Injector (OHDT) Design and Operation: The OHDT is the tool which drills the hole and injects the AS into the formation. It includes pumps, sample chambers, optical fluid analyzers of the flowline, and the 9mm diameter drill with single probe Figs 5 - 7. Pretests are used to locate the formation with the highest fluid mobility, krw/w in units of mD/cP. The pretest algorithm that calculates the mobility accounts for the drilled tunnel geometry by calculating the surface area at each successive deepening of the drilled hole (Burgess et al, 2001). The mobility from this pretest should be close to that measured by the previous run of the wireline formation tester which was used to select this injection depth. A 9mm diameter hole is then drilled to a penetration depth of 7.62cm (3-in) and the mobility measurement repeated. This second mobility should be equal or higher than the first mobility. The drilling operation is monitored with real-time measurements of

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penetration, torque and weight on bit. The bit is automatically frequently tripped in and out of the hole to remove cuttings. The bit trips can be manually repeated without drilling if a torque increase indicates a buildup of cuttings. After drilling to a penetration depth of 15.2cm (6-in) reservoir fluids are produced to clean the drilled hole of any cuttings that could adversely affect the subsequent injection. A high rate pump beneath the probe in the OHDT draws fluid from the hole into the tool, down through an optical fluid analyzer, and into the mud column through an opened port at the bottom of the tool. The fluid analyzer is used to monitor for cuttings and for oil and gas if the flow period is long enough to draw hydrocarbon into the tool Fig 8. This pump is capable of high rates as there is no limit on the drawdown of the reservoir because this tight carbonate formation is competent rock and is unlikely to collapse under high pressure differential. The buildup of reservoir pressure following this flow period is also used to derive the fluid mobility. Now the flow line in the OHDT from the drilled hole into the tool to the junction with the main flowline, and the main flowline itself beneath this junction is full of mud filtrate or hydrocarbon. The main flowline above this junction leading to the AS filled sample chambers needs to be flushed clean. This is achieved using another pump, this time a low rate pump positioned in the tool string above the probe beneath the AS filled sample chambers. About 1 liter of AS is pumped down the flowline past a second upper optical fluid analyzer, past a closed valve isolating the probe and drilled hole, past the lower fluid analyzer, and out into the mud column through an opened port at the bottom of the tool. This flushing continues until both fluid analyzers show clear fluid. This upper fluid analyzer is used to monitor the purity of the AS during injection. With only AS in the flowline the bottom exit port is closed, the valve to the probe and drilled hole is opened, and the AS is injected into the formation with the upper slow rate pump. This pump has an operating range of 0.2 to 1.6 cc/sec. Mud filtrate and AS are both clear fluids so look similar to the optical fluid analyzer, but can be clearly distinguished with a measurement of the resistivity of the fluid in the flow line. The mud filtrate is 0.034m whilst the AS is 0.13m. At the beginning of injection all the sample chambers containing AS are opened. This avoids subsequent pressure or flow rate surges if they were opened sequentially. There are two ways to configure the sample chambers. For injection pressures beneath hydrostatic the volume behind the floating piston in the sample chamber is closed, and this volume is filled with air pressurized to the reservoir pressure. During injection this air pressure will help the pump, without supplying the pump with AS that exceeds the reservoir pressure. Eventually as the sample chamber is depleted of AS the air pressure will decrease, increasing the pressure differential the pump has to overcome. Ultimately there will be some AS left in the sample chamber that cannot be injected. For injection pressures above hydrostatic the volume behind the floating piston in the sample chamber is open to hydrostatic. This means the injection pressure will abruptly increase from reservoir pressure to hydrostatic pressure at the beginning of injection. The load on the injection pump is reduced, and all the sample contents will be injected. Injection Results First depth: The first attempt to inject AS was in the Lower Shuaiba. The mobilities ranged from 1.5 mD/cP before drilling to 1.6 mD/cP after drilling to a depth of 3-in, and 2.2 mD/cP after drilling to a depth of 6-in. These mobility variations are within the uncertainty of the measurement. One liter of formation fluid was then produced with a mobility of 1.5 mD/cP, a short bit trip was performed to verify the stability of the drilled hole and an attempt was made to inject AS. Every time the injection pressure approached the hydrostatic pressure the injection was manually truncated, and the pressure bled off into the formation. This was to reduce the risk of seal failure, which was considered a likely occurrence if the injection pressure exceeded the hydrostatic pressure. After several hours of saw tooth injection pressure cycles the resistivity of the flowline indicated not even the 200cc flowline volume of mud filtrate 0.034 m had been injected and replaced by less conductive 0.13 m AS. Another liter of formation fluid was produced to confirm the hole had not become plugged. The mobility of this short clean up production was 1.9 mD/cP. Further attempts at matrix injection with the slowest possible injection rate of 0.2 cc/sec. were also unsuccessful. The initial intention to inject the AS into the reservoir at injection pressures below the hydrostatic pressure was abandoned, and the injection pressure was increased above hydrostatic pressure. The seal was not lost, however still the formation apparently did not take any fluid. The injection pressure was further increased in 500 kPa increments, with pressure declines between each increment. Eventually the formation breakdown pressure was reached at 19080kPa. From the first fall off after this fracture initiation the instantaneous fracture shut in pressure was 18700kPa corresponding to the moment the pump is stopped, followed by the fracture closure pressure of 17920kPa. Subsequent increases in the injection rate by increasing the hydraulic motor speed from 300 to 1800rpm did not alter the injection pressure, which fluctuated around the fracture propagation pressure. This insensitivity to injection rate suggested fracture propagation is dominating, with little to no matrix injection. Of the six injection cycles following the fracture initiation the fracture propagation pressure from the last three of 17500 to 17700 kPa were the most consistent, indicating the micro fracture had reached deep enough into the formation to see far field stress conditions. These formation breakdown stresses are within the range measured in the surrounding water injectors. The post-injection borehole image did not show any evidence of matrix flood Figs 9 - 10. Second depth: The Kharaib was selected for the second injection point. Before drilling the mobility was 2.3 mD/cP, at 3-in drilled hole depth it was 1.6 mD/cP and at 6-in drilled hole depth the mobility was 1.9 mD/cP. After producing for a short time the mobility was 1.5 mD/cP, and injection was attempted. The injection pressures increased less rapidly for one cycle, and then further injection was impossible despite multiple attempts. A further 10.7 liters in total of mud filtrate and

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hydrocarbon was produced in two flow periods of 5.8 liters and 4.9 liters prior to trying to inject again. The mobility from this flow period was 2 mD/cP. Now it was possible to inject fluid at the minimum hydraulic motor speed of 300 rpm. The injection rate varied from 0.2 cc/second to 0.18 cc/second for the remainder of this Kharaib injection, which continued for 3 liters with an increase in injection pressure to within 1000kPa of the expected fracture initiation pressure. After injection the two mobility measurements were 4.4 and 3.9 mD/cP; a 100% increase from pre-injection. This may suggest that the AS has created a volume of rock with less oil, therefore increasing the mobility of the continuous water phase. The post-injection electrical borehole image showed a 10cm diameter conductive circular flushed zone surrounded by an oil bank. There was a check trip between the injection and post-injection logging during which the drillpipe was rotated. It is postulated that the conductive mud filtrate must have replaced the less conductive AS creating this clear image. The NMR was not run because the 15.24cm antenna would not resolve this 10cm flood Figs 11 - 14. Third depth: The third injection point was a second attempt in the Lower Shuaiba reservoir. The mobility prior to drilling was 1.8md/cp, the mobility at 3-in deeper into the formation was 2.9md/cp and at 6-in deeper into the formation was 3.4md/cp. This time twenty-one liters of mud filtrate and oil was produced prior to injection. After accepting one liter the injection pressures increased rapidly. Each time this happened the injection pump was stopped before reaching fracture breakdown pressure. It was thought once a fracture was opened it would be impossible to achieve a matrix flood. The cleanup flow periods were repeated twice in case the hole had become plugged, but the subsequent injection attempts still failed. Finally the injection pressure was increased to the formation breakdown pressure at 18870 kPa. After one liter of fluid injected at frac pressures the injection pressure dropped. To determine whether this had become matrix injection a measurement was made of the sensitivity of the injection pressure to the injection rate. The injection rate was reduced by 60% in three steps, and then increased in two steps to 1.5 cc/second. The injection pressure tracked this change in injection rate. The final injection rate was kept constant and the injection pressure of 15500 kPa slightly dropped. This is thought to be due to the AS creating a volume of decreased oil saturation, therefore increased water mobility. The pressure falloff after the final injection was analyzed with pressure versus square root elapsed time. There was no evidence of a fracture closing supporting the conclusion that this 15500 kPa was matrix injection and not the fracture propagating. The pretest mobility of 4.2 and 4.3 mD/cP measured at the end of this test was 50% higher than the first pretests. The post-injection borehole image showed some matrix invasion had taken place, but less than what was seen at the three liter Kharaib injection. The image showed a small flushed zone surrounded by a larger oil bank. This is somewhat surprising and it is possible that the deeper nineteen liter matrix flood pushed some oil back towards the borehole, with the majority of the matrix flood beyond the investigation depth of the imaging tool and the ADT Figs 15 - 17. There is a possible explanation for the ability to inject at 5210 kPa (755 psi) above the mud pressure with the seal preserved by only a 7.3cm by 4.5cm rubber pad. The induced pressure field does not intersect the well bore except in the zone covered by the small pad because the spatial pressure gradient in this tight formation is very high and moves very slowly. In the time frame of the job, several days, the elevated pressure surrounding the drilled hole was covered by the rubber pad. Neither did the induced fracture intersect the wellbore because the least resistance for a propagating fracture that started near the end of a horizontal 6-in deep hole is away from the stress disturbed region caused by the vertical 6 1/8-in open hole. Discussion of Results Change in ROS: This analysis was only possible for the second depth that achieved a matrix flood of 3 liters. The oil saturation measured before injection by the NMR tool at the same relative bearing as the drilled hole is 32%. All the attempts to orientate the ADT tool before injection at this depth were unsuccessful. The oil saturation after AS injection measured by the average of three passes of array dielectric tool (ADT) across the 10cm flushed zone is 18%. Therefore the decrease in remaining oil saturation at this particular injection point due to the AS is 14 saturation units. The NMR tool was not run after injection as the 15.46cm antenna length would not have resolved this small flood. Comparing results with SWCT and Cased Hole Saturation Logs: The MicroPilot* and SWCT were in broad agreement, but the cased hole saturation logs measured higher ROS, with significantly less ROS change following the injection of AS. The attempts with the OHDT to inject AS into the tight carbonate demonstrated the difficulty initiating a matrix flood without the unintentional creation of micro fractures. The presence of these micro fractures in the near wellbore region at the injection depths provides a possible explanation for the discrepancy between the cased hole saturation logs and SWCT acquired during the same AS injection test. Micro fractures will leave bypassed oil in the near wellbore region. The measurement volume of the shallow volumetric nuclear logs is 10cm radial depth for carbon/oxygen and 25cm radial depth for thermal neutron decay. This shallow bypassed oil will have a smaller impact on SWCT tracers that penetrate 3m. In addition any relatively tighter regions of the rock that are not accessed by either the SWCT tracers or the AS will not be reflected in the ROS change measured by the SWCT. The creation of these micro fracs confirms similar field observations seen in water injector wells and may not be negative for the ultimate recovery as small micro-fracs provide access paths into the matrix formation. The measurement of the macro

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recovery that includes any oil bypassed due to induced fractures will require a multi-well pilot with possible dedicated observation wells. Saturation logs recorded in cased observation wells without perforations will be unaffected by near wellbore fluid dynamics associated with micro fractures. Recommendations: The NMR depth log was not used to select the injection depths. The T2 relaxation distribution available from the NMR reflects the pore size distribution, which may change even if the total porosity does not. The NMR depth log did show permeability variation due to the occasional presence of perceived macro pores, evidenced by some of the porosities having long T2. This approach could have been used to improve the selection of the injection depth because macro pores increase the permeability. This means the NMR would be run twice; as a depth log combined with the first logging run, PEX-HRLA, to increase the information available for injection point selection, then again for the NMR fluid saturation stations across the short pre-selected depth intervals. Conclusions The Micropilot* test has provided another part of the puzzle in the road to assess the attractiveness and feasibility of a possible chemical EOR project in the conventional carbonate waterflood developments in North Oman. At one depth in this 3mD carbonate it was possible to inject enough AS to create a measurable flushed zone. This has demonstrated that even in formations with permeabilitys as low as 3mD it is possible to consider chemical EOR. This test has also demonstrated that it is possible to inject fluids with a single probe tool up to the fracture pressure without losing seal. The drop in remaining oil saturation resulting from this AS injection was consistent with the SWCT result. In addition to the measurement of remaining oil saturation, other information available from this test includes the response of tight carbonate to the injectivity of the EOR fluid and the increase in EOR fluid mobility with the progression of the flood. Acknowledgements The authors would like to thank the Ministry of Oil and Gas, Petroleum Development Oman and Schlumberger for authorizing the publication of this work. References

Burgess K.A. et al, Wireline-Conveyed Through-Casing Formation Tester Preserves Casing Integrity, SPE 72371, SPE Eastern Regional Meeting, Canton, Ohio, USA, 17-19 October 2001

Deans, H.A. et al, "The Single-Well Chemical Tracer Test - A Method For Measuring Reservoir Fluid Saturations In Situ" Petroleum Engineering Handbook, Larry W. Lake, SPE, Volume V, Reservoir Engineering and Petrophysics, pp 615-649, 2007

Hizem et al, Schlumberger, A New Wireline Petrophysical Measurement SPE 116130, SPE Annual Technical Conference, Denver Colorado USA, 24-28 September, 2008

Orban et al, Schlumberger, Development and Use of Improved Wireline Formation Tester Technologies in Challenging Deltaic Reservoirs SPE 120691, SPE Asia Pacific Oil and Gas Conference Jakarta, Indonesia, 46 August, 2009

Pradeep et al, PDO and SchlumbergerAnalysis and Flow Modeling of Single Well MicroPilot* to Evaluate the Performance of Chemical EOR Agents, SPE 136767, International Petroleum Exhibition & Conference Abu Dhabi, UAE, 14 November 2010

Shyam et al, PDO and Schlumberger, Analysis and Flow Modeling of Single Well MicroPilot to Evaluate the Performance of Chemical EOR Agents, SPE 129069, SPE EOR Conference at Oil & Gas West Asia, Muscat, Sultanate of Oman, 11-13 April 2010

Soek et al, PDO, Plans for Chemical Enhanced Oil Recovery in a North Oman Carbonate Field, SPE 139537, Middle East Oil and Gas Show, Bahrain, 13-16 March 2011

Stoll et al, Shell, Alkaline-Surfactant-Polymer Flood: From the Laboratory to the Field SPE 129164, SPE EOR Conference at Oil & Gas West Asia, Muscat, Sultanate of Oman, 11-13 April 2010

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Densitytotalporosity

ADTwaterfilledporosityFigure 1. Dielectric tool radiation pattern for the longitudinal dipole polarization. Vertical resolution is 1-in.

Figure 2. NMR tool and measured volume cross section The NMR vertical resolution when taking stationary measurements is 6-in

Figure 3. Lower Shauiba pre-injection comparison of ADT logs and NMR station measurements. Water saturation on the left, porosity on the right. The dots are NMR oil saturations and total porosities, the saturation log is from the ADT, and the porosity log is from PEX density. The depth lines are every 0.1m.

Figure 4. NMR stations before injection above and below the Kharaib injection depth. Above on the left, oil saturation 32.6% and total porosity 29.4 PU, below on the right, oil saturation 31.3% and total porosity 29.1 PU.

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Figure 5. Openhole Driller-Injector with 9 mm bit.

Figure 6. Drilled hole through casing and cement from the Openhole Driller-Injector. The drilling tool can be configured for operation in cased or an open hole.

Figure 7. Openhole Driller-Injector flowline Figure 8. Optical fluid analyzer during cleanup with 10% oil. This is from the second depth, the Kharaib.

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Figure 9. First depth, Lower Shuaiba. Matrix injection was not possible. This became a stress test.

Figure 10. Fracture propagation pressures for Figure 9, the first depth. The time scale in this figure has a floating time start point different for each applied pressure cycle, with each start point corresponding to an arbitrary time on Fig 9. just preceding the application of each pressure cycle. This provides a repeat analysis of each fracture propagation.

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Figure 11. Second depth, Kharaib. Matrix injection of 3 liters at 0.2 cc/second.

Figure 12. Second depth, Kharaib matrix flood. On the left is the static image before and after injection. On the right is the dynamic image before and after injection. The green square is 10cm.

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Figure 13. Second depth, Kharaib matrix flood. On the right are the static FMI images before and after the AS injection of three liters. On the left are two log tracks. The left track displays the water saturations computed from the each of the three ADT passes after AS injection, and the NMR station water saturations acquired before injection. The difference in saturation from before to after injection is indicated by the two short red lines, 14 saturation units. The right log track displays the dielectric water filled porosity from the each of the three ADT passes after AS injection, and the NMR station water filled porosities acquired before injection.

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0 0.2 0.4 0.6 0.8 10

0.2

0.4

0.6

0.8

1

Sw

Krw

, Kr

oRelative Permeability

Sw =68%beforeinjectionfromlogs

Sw =81%estimatedfromKrw increaseafterinjection

100%Krw/mobilityincreasefromSw 68%correspondstoSw 81%

Krw doubled

Figure 14. Second depth, saturation versus relative permeability. For a mobility increase of 100% from 2 mD/cP to 4 mD/cP as for the Kharaib matrix flood, the corresponding water saturation increases from 68% to 81%.

Figure 15. Third depth, Lower Shuaiba, frac then matrix injection

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Figure 16. Lower Shuaiba injection depths, first and third depth, static image, before injection on left, after injection on right.

Figure 17. Lower Shuaiba injection depths, dynamic image of Figure 16

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