One of the North Kuwait Carbonate fields which starts its production in 1957 has very low recovery factor after 60 years of production although the field was under water flooding since 1997. A workflow was developed to first understand the reason behind the low recovery and second to propose the best way to improve it.
The workflow starts with first building a material balance model to understand the main reservoir driving mechanisms. Second, a fine-scale history matched simulation model was used to understand the main reasons of the current low recovery. A Produce High and Inject Low (PHIL) concept was proposed with locating all the injectors at the deepest zone and the producers at the shallow zones. Finally, the proposed PHIL concept with inverted 5-spot horizontal wells was examined compared to the inverted 9-spot vertical wells and to the peripheral PHIL concept using the simulation model to examine the best approach to maximize the recovery.
Different outcomes from the above-mentioned workflow can be summarized as follows; first, it was found that the main driving mechanism is water injection which represents 70% of the reservoir recovery factor. Hence the importance of creating an artificial aquifer along the whole area of the field to provide the required pressure support which calls for the implementation of the PHIL concept with inverted 5-spot pattern background as the best development concept for the field. Second, the thorough data review used on building the fine-scale model shows that the current recovery is dominated by single zone which represents only 15 % of the in-place and on top of this, it was found that all the developed wells are located only on 30% of the field leaving 70% of the field undeveloped. These are the main reasons behind the low recovery. Finally, the developed PHIL concept with inverted 5-spot background shows that the recovery can be increased by five times with less number of new wells and less water injection volume required compared to the 9-spot vertical wells and the peripheral PHIL concepts. This five-folds increase in recovery encourages the asset to do a pilot to implement the proposed development strategy.
Unlike the commonly used inverted 5-spot vertical wells, this work proposes a novel approach of inverted 5-spot horizontal wells with directing the horizontal injectors at the deepest zones and the horizontal producers at the shallow zones. Hence creating an artificial bottom aquifer with minimizing the water production and maximizing the water injection distribution along the whole area of the reservoir.
Injection of sea water (SW) into oil reservoirs for pressure maintenance or sweep can in some cases cause reservoir souring, sulphate scaling and formation damage. Change of injection water from SW to desulphated sea water (D-SW) may reduce these problems. The objective for the presented study was to investigate the interactions between reservoir chalk rocks and D-SW, and to determine the effects of low sulphate concentration in formation water (FW) on oil production from reservoir chalk.
FW, SW, D-SW (synthetic) and water from a sulphate removal plant (SRPW) were injected to reservoir chalk plugs. Effluent samples were analysed for sulphate, pH and elements to investigate the interactions between brines and minerals. During the brine injections, the potential for formation damage was also evaluated by measuring differential pressure across the core plugs. Reservoir chalk plugs were prepared using FW without sulphate and FW with sulphate concentration as in real FW, to investigate the effect of initial sulphate on spontaneous imbibition and viscous flooding.
No pressure build-up was observed when FW, SW, D-SW and SRPW were injected to the reservoir chalk plugs. Sulphate effluent peaks were observed during injection of FW, D-SW and SRPW to the reservoir chalk. The effluent pH was higher in the D-SW and SRPW injections than in the FW injections. The compositions of effluent samples confirmed the interactions between the reservoir chalk and these brines. Both spontaneous imbibition and viscous flooding with SW showed that the reservoir chalk with initial sulphate was more water-wet than the same chalk without initial sulphate.
Injection of D-SW will reduce the amount of sulphate produced in the oil fields, but the study has shown that sulphate will be produced due to the release of sulphate from the original reservoir chalks. Since SW has been reported to improve the oil recovery, it is important to compare the oil recovery potential for D-SW and SW before the type of injection brine is selected. It will then be important to prepare the reservoir rock with the correct amount of initial sulphate.
Rock, Alexander (Clausthal University of Technology) | Hincapie, Rafael E. (Clausthal University of Technology) | Hoffmann, Eugen (Clausthal University of Technology) | Ganzer, Leonhard (Clausthal University of Technology)
This work provides an extensive review on Low Salinity Water Flooding (LSWF) recovery mechanisms, as well as an evaluation of its synergies with Polymer Flooding (PF). Thereby, a critical state-of-the-art evaluation on LSWF and PF mechanisms is combined with selective laboratory experiments, performed to illustrate the observations and findings. This evaluation can be used as a guidance to understand the expected behavior of both processes when applied in combination.
The work presented here comprises two main steps: 1) Comprehensive review of the mechanisms responsible of oil recovery in each process and 2) Predefined secondary and tertiary mode flooding experiments. First, oil recovery mechanisms associated to LSWF and PF have been analyzed in detail. Second, different field cases were compared in order to draw the main conclusions with regards to performance and recovery factors. This also helped to define the synergies of LSWF and PF in terms of technical and economic efficiency. Finally, secondary and tertiary mode experiments were performed to evaluate the feasibility of applying both processes.
Despite of the over 15 mechanisms reported in the literature for LSWF, six main mechanisms were identified that contributes to oil recovery. Mechanisms are described as: 1) Wettability alteration 2) Multi-ion exchange, 3) Fine migration, 4) Salting-in, 5) Double-Layer-Expansion and, 6) Other mechanisms, such as osmotic pressure and IFT reduction. Thereby, wettability alteration and fine migration have the highest significance. On the other hand, PF mechanisms were found to be: 1) Viscous fingering reduction, 2) Enhanced flow between layers, 3) Pull-out effects, 4) Shear thickening/elastic turbulence and, 5) Relative permeability reduction. LSWF field cases revealed incremental recoveries of up to 13% OOIP whereas synergies between LSWF and PF yielded to an additional recovery of 15% OOIP, underlining the potential of the combination of both EOR technologies. Selective LSWF-PF experiments performed in sandstones core-plugs in this work, allowed the verification of the additional recoveries reported in the literature. Tertiary flooding with solely LSWF, showed a lower recovery than tertiary LSWF-PF flooding. Moreover, this observation confirms the potentiality of polymer-combined LSWF in sandstones. Additionally, with the combined processes, a lower polymer concentration was required than applying a typically designed polymer flooding. This can be translated to an economic benefit for field applications.
Tertiary mode flooding experiments in sandstones and the analysis of field cases provided clear evidence of the advantages of LSWF-PF. This could yield that the processes -when applied in tandem- become a leading EOR strategy, ensuring the extension of the reservoir lifetime. Moreover, fellow researchers can benefit because the work provides a comprehensive review of Low Salinity Water Flooding and Polymer Flooding mechanisms. To the authors understanding, literature is currently lacking of such a review.
Puntervold, Tina (University of Stavanger) | Strand, Skule (University of Stavanger) | Torrijos, Iván D. Piñerez (University of Stavanger) | Hopkins, Paul (University of Stavanger) | Austad, Tor (University of Stavanger)
EOR by Smart Water injection in calcite, CaCO3, is dependent on factors like initial wetting, injection brine composition and temperature. Because of the chemical difference between CaCO3 and dolomite, CaMg(CO3)2, the relationship between EOR effects and the above-mentioned factors could be different. Smart Water EOR potential was experimentally tested for two dolomitic reservoir systems, at low and high reservoir temperature, to determine if there was a temperature limitation for observing EOR effects by Smart Water injection.
Oil recovery tests by spontaneous and forced imbibition experiments were performed to evaluate initial wetting and wettability alteration from two dolomitic reservoir systems. A fractured reservoir system at 65 °C was investigated by spontaneous imbibition tests, while a non-fractured system at 115 °C was investigated by forced imbibition tests. The reservoir cores were saturated with their respective formation waters and crude oil, then imbibed with diluted seawater or modified seawater brines. Oil recovery responses at the different temperatures and by using different imbibing brines were evaluated and compared.
Spontaneous imbibition tests, performed in the fractured reservoir system, showed that a diluted seawater brine increased the oil recovery from the dolomitic core material at 65 °C. When a modified seawater brine, which is a Smart Water for CaCO3, was used, there was no EOR effect observed. Forced imbibition tests with diluted seawater brine showed increased oil recovery for a non-fractured dolomitic reservoir system at 115 °C, while a modified seawater resulted in no extra oil produced.
The results showed that there was no temperature limitation for observing EOR effects in dolomitic reservoir core material within the temperature range 65 - 115 °C. It was confirmed that diluted seawater brines altered the initial core wettability towards more water-wet conditions and enhanced oil recovery was observed both in spontaneous imbibition and forced imbibition experiments. Due to the differences in mineralogy between CaCO3 and dolomite, CaMg(CO3)2, and in their chemical reactivity, the optimal injection water, i.e. Smart Water compositions, were different.
Smart Water EOR effects by wettability alteration in dolomitic reservoir material were observed both at low and high reservoir temperatures. The final oil recovery was dependent on the injection brine composition. Increased oil recovery was experienced in both spontaneous and forced imbibition tests.
Arshad, Muhammad Waseem (Technical University of Denmark DTU, DTU Chemical Engineering, Center for Energy Resources Engineering, Søltofts Plads 229, DK-2800 Kongens Lyngby) | Loldrup Fosbøl, Philip (Technical University of Denmark DTU, DTU Chemical Engineering, Center for Energy Resources Engineering, Søltofts Plads 229, DK-2800 Kongens Lyngby) | Shapiro, Alexander (Technical University of Denmark DTU, DTU Chemical Engineering, Center for Energy Resources Engineering, Søltofts Plads 229, DK-2800 Kongens Lyngby) | Thomsen, Kaj (Technical University of Denmark DTU, DTU Chemical Engineering, Center for Energy Resources Engineering, Søltofts Plads 229, DK-2800 Kongens Lyngby)
Smart water flooding is an advanced method for enhanced oil recovery (EOR) in which the composition of injected brine is altered by varying the concentration of selected ions that can increase the oil recovery from various carbonate reservoirs. Besides wettability alteration mechanism, the formation of water-soluble oil emulsions has been reported as a possible reason to explain the observed increase in oil recovery using smart water. The formation of water-soluble oil emulsions takes place on the interaction of insoluble salts (fines) with oils. However, the interaction of these fines with the crude oil is not very well studied for carbonate reservoirs. This work presents emulsion formation in water-oil systems in the presence of water-insoluble fines. The effect of amount of fines on emulsion formation is also examined.
Synthetic seawater (SSW) and deionized water (DIW) were used as water phase, two model oils (decane (D) and 1:1 vol. ratio of hexane-hexadecane (HH) mixture) and North Sea crude oil (NSCO) were used as oil phase, and fines of CaCO3 (≤ 30 µm) and CaSO4 (≈ 44 µm) were used as solid phase. Branson Sonifier® SFX250 was used for emulsion formation (based on the principle of ultrasonic processing). All the experiments were performed for the same conditions of 5 minutes of ultrasonic processing at an output power of 30 W by using 6.5 mm tapered microtip (sonication probe). Emulsion characterization was done by using an optical microscope (Axio Scaope.A1).
Several combinations of water-oil-fines were tested. The tests consisted of control experiments (in which only water-oil without any fines were tested) and water-oil-fines experiments. In the control experiments (without fines), SSW did not show any tendency to emulsify neither with the model oils nor with NSCO. However, DIW showed clear tendency to emulsify with model oils and NSCO. Amongst model oils, DIW emulsified with HH better compared to decane. Similar results were observed in the water-oil-fines experiments. SSW did not form any emulsion with the model oils in the presence of fines of CaCO3 and CaSO4. However, significant amounts of emulsion formation were observed when DIW was sonicated with model oils and fines. HH formed more emulsions compared to decane. For NSCO case, both SSW and DIW formed a significant amount of emulsions with both types of fines (CaCO3 and CaSO4). An increase in amount of fines showed an increase in emulsion formation and a better emulsion stabilization. Sonication is a quick and reliable technique to screen out emulsion formation in different combinations of water-oil-fines.
This work will further develop our understanding of emulsion formation in the water-oil-fines systems.
Adjusting the injection-water chemistry during waterflooding for both carbonate and clastic reservoirs shows a significant effect on oil recovery. In carbonates, however, the role of ions plays a key role in rock/fluid interaction, and eventually affects the rock wettability. Research studies for carbonate-rock systems have been continuously conducted to identify the reaction mechanisms that modify the rock wettability toward water-wet. Most of these studies are conducted at macroscopic scales by use of conventional methods such as coreflooding, contact-angle, and imbibition/drainage procedures. Potential mechanisms for rock-wettability alteration were proposed including sulfate (SO4) adsorption, mineral dissolution, ionic exchange, and improving fluid diffusion among different pore systems. Further research studies have noted that certain ions have a significant role in the proposed mechanisms. Moreover, the main interactions are expected to take place at rock/fluid and/or fluid/fluid interfaces.
In this paper, more attention is given to indirect measurements of carbonate- and crude-oil-surface charges at different ionic composition and temperatures by use of unique preparation procedures and advanced techniques. Individual and combined dissolved cations and anions were studied at fixed salinity. An ultrasonic homogenizer bath was used to create oil-in-water emulsions and carbonate suspensions in different brines at high temperatures. To determine the interactions between immiscible fluids with carbonates, oil-in-water emulsions were prepared in the presence of carbonate particles. To mimic the reservoir condition, the aging effect on the chemical interactions of emulsions and carbonate suspensions was investigated.
The findings in this study bring new insights on the effect of different ions on crude-oil components and carbonate-rock interactions at fixed salinity. Individual ions including cations and anions altered carbonate-surface charges and interacted differently at interfaces, although all water recipes have the same salinity. Individual sodium (Na) salts, in particular, significantly influenced the surface potential at the calcite/water interfaces. The hard ions as calcium (Ca) and magnesium (Mg), on the other hand, shifted the ζ-potential of calcites toward the positive side. These divalent ions can either adsorb directly on the negative sites or penetrate the adsorbed hydrolysis layer of water on the calcite surface. The electrical properties of calcites are also affected by the ionic content and the cation/anion ratio, as in SmartWater (a mixture of dissolved salt species such as cations and anions) (Yousef et al. 2012) and key ion solutions. In addition, the dissolved divalent cations can play a role in the interactions at the Stern-layer boundary and eventually they can affect the surface charges at oil/water interfaces. In view of the ζ-potential results, only SmartWater, sodium chloride (NaCl), and sodium sulfate (Na2SO4) solutions were able to create electrical repulsions between oil/water and calcite/water interfaces. As a result, wettability of the rock will be altered to water-wet, thus enhancing oil recovery.
Bartels, Willem-Bart (Utrecht University) | Mahani, Hassan (Shell Global Solutions International B.V.) | Berg, Steffen (Shell Global Solutions International B.V.) | Menezes, Robin (Delft University of Technology) | van der Hoeven, Jesse A. (Utrecht University) | Fadili, Ali (Shell Global Solutions International B.V.)
W.-B. Bartels, Utrecht University; H. Mahani and S. Berg, Shell Global Solutions International B.V.; R. Menezes, Delft University of Technology; J. A. van der Hoeven, Utrecht University; and A. Fadili, Shell Global Solutions International B.V. Summary Low-salinity waterflooding (LSF) is receiving increased interest as a promising method to improve oil-recovery efficiency. Most of the literature agrees that, on the Darcy scale, LSF can be regarded as a wettability-modification process, leading to a morewater-wet state, although no consensus on the microscopic mechanisms has been reached. To establish a link between the pore-scale and the Darcy-scale description, the flow dynamic at an intermediate scale--i.e., networks of multiple pores--should be investigated. One of the main challenges in addressing phenomena on this scale is to design a model system representative of natural rock. The model system should allow for a systematic investigation of influencing parameters with pore-scale resolution while simultaneously being large enough to capture larger-lengthscale effects such as saturation changes and the mobilization and connection of oil ganglia. In this paper, we use micromodels functionalized with active clay minerals as a model system to study the low-salinity effect (LSE) on the pore scale. A new method was devised to deposit clays in the micromodel. Clay suspensions were made by mixing natural clays (montmorillonite) with isopropyl alcohol (IPA) and were injected into optically transparent 2D glass micromodels. After drying the models, the clay particles were deposited and stick naturally to the glass surfaces. The micromodel was then used to investigate the dependence of the LSE on the type of oil (crude oil vs. n-decane), the presence of clay particles, and aging. Our results show that the system is responsive to low-salinity brine as the effective contact angle of crude oil shifts toward a more-water-wetting state when brine salinity is reduced.
Mahani, Hassan (Shell Global Solutions International B.V.) | Keya, Arsene Levy (Shell Global Solutions International B.V.) | Berg, Steffen (Shell Global Solutions International B.V.) | Nasralla, Ramez (Shell Global Solutions International B.V.)
Laboratory studies have shown that wettability of carbonate rock can be altered to a less-oil-wetting state by manipulation of brine composition and reduction of salinity. Our recent study (Mahani et al. 2015b) suggests that surface-charge alteration is likely to be the driving mechanism of the low-salinity effect in carbonates. Various studies have already established the sensitivity of carbonate-surface charge to brine salinity, pH value, and potential-determining ions in brines. However, in the majority of the studies, single-salt brines or model-carbonate rocks have been used and it is fairly unclear how natural rock reacts to reservoir-relevant brine as well as successive brine dilution; whether different types of carbonate-reservoir rocks exhibit different electrokinetic properties; and how the surface-charge behavior obtained at different brine salinities and pH values can be explained.
This paper presents a comparative study aimed at gaining more insight into the electrokinetics of different types of carbonate rock. This is achieved by ζ-potential measurements on Iceland spar calcite and three reservoir-related rocks—Middle Eastern limestone, Stevns Klint chalk, and Silurian dolomite outcrop—over a wide range of salinity, brine composition, and pH values. With a view to arriving at a more-tractable approach, a surface-complexation model (SCM) implemented in PHREEQC software (Parkhurst and Appelo 2013) is developed to relate our understanding of the surface reactions to measured ζ-potentials.
It was found that regardless of the rock type, the trends of ζ-potentials with salinity and pH are quite similar. For all cases, the surface charge was found to be positive in high-salinity formation water (FW), which should favor oil-wetting. The ζ-potential successively decreased toward negative values when the brine salinity was lowered to seawater (SW) level and diluted SW. At all salinities, the ζ-potential showed a strong dependence on pH, with positive slope that remained so even with excessive dilution. The sensitivity of the ζ-potential to pH change was often higher at lower salinities.
The existing SCMs cannot predict the observed increase of ζ-potential with pH; therefore, a new model is proposed to capture this feature. According to modeling results, formation of surface species, particularly >CaSO–4 and to a lower extent >CO3Ca+ and >CO3Mg+, strongly influence the total surface charge. Increasing the pH turns the negatively charged moiety >CaSO–4 into both negatively charged >CaCO–3 and neutral >CaOH entities. (Note that throughout this paper, the symbol > indicates surface complexes.) This substitution reduces the negative charge of the surface. The surface concentration of >CO3Ca+ and >CO3Mg+ moieties changes little with change of pH.
Nevertheless, besides similarities in ζ-potential trends, there exist notable differences in terms of magnitude and the isoelectric point (IEP), even between carbonates that are mainly composed of calcite. Among all the samples, chalk particles exhibited the most negative surface charges, followed by limestone. In contrast to this, dolomite particles showed the most positive ζ-potential, followed by calcite crystal. Overall, chalk particles exhibited the highest surface reactivity to pH and salinity change, whereas dolomite particles showed the lowest.
Electrokinetic Low-concentration acidizing is one of the emerging technologies where the application of the Low-concentration acidizing is integrated with electrokinetic enhanced oil recovery (EK-EOR) as presented in previous studies [
Core-flood tests were conducted by saturating Abu Dhabi carbonate core-plugs with medium crude oil in a specially designed core-flood setup at reservoir conditions. After the waterflooding stage, EK LCA-IOR was applied under optimum conditions (1.2% HCl concentration, 1V/cm voltage gradient), where acid was injected and transported by EK to the target producer. Moreover, the capillary number change, Single Energy CT Scan (SECTS) and oil API gravity change results were analyzed in order to observe the effect on rock-fluid interaction to control rock adsorption capacity through interfacial tension and depth of penetration.
Several correlations at reservoir conditions related to acid concentration, displacement efficiency and permeability enhancement have shown that the application of waterflooding on the carbonate cores yields an additional 15-28% oil recovery beyond the waterflooding limit (58%), recording a maximum oil displacement efficiency of 88% and maximum permeability enhancement of 53%.EK LCA-IOR also improves the capillary number by 500% in Water-wet core plugs and 1500% in Oil-wet core plugs, mainly due to a decrease in interfacial tension, increase in crude oil API gravity by 20-40% with an increase in API gravity of about 10-18%. The use of SECT imaging confirmed wormhole orientation and propagation length across core-plugs, precisely delivering the acid front throughout the core-plug and also indicate the decrease in acid adsorption as acid is precisely transported to the targeted production well through the tortuous path.
EK LCA-IOR may offer a feasible option to augment the efficient unswept oil displacement allowing us to save on the OPEX by maintaining decreased power consumption while reducing the acid/water requirement upto 10 times as compared to currently applied conventional EOR methods. This study takes one step forward towards the development of EK LCA-IOR method feasible for complex tight carbonate reservoirs in UAE.
Nasralla, Ramez A. (Shell Global Solutions International B.V.) | Sergienko, Ekaterina (Shell Global Solutions International B.V.) | Masalmeh, Shehadeh K. (Shell Abu Dhabi) | van der Linde, Hilbert A. (Shell Global Solutions International B.V.) | Brussee, Niels J. (Shell Global Solutions International B.V.) | Mahani, Hassan (Shell Global Solutions International B.V.) | Suijkerbuijk, Bart M. J. M. (Shell Global Solutions International B.V.) | Al-Qarshubi, Ibrahim S. M. (Shell Global Solutions International B.V.)
Low-salinity waterflood (LSF) is a promising improved-oil-recovery (IOR) technology. Although, it was demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established because only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil-recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments.
This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater (SW) and several dilutions of formation brine and SW were flooded in the tertiary mode to evaluate their impacts on oil recovery compared with formation-brine injection. In addition, a geochemical study was performed with PHREEQC software (Parkhurst and Appelo 1999) to assess the potential of calcite dissolution by LSF.
The experimental results confirmed that lowering the water salinity can alter the rock wettability toward more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, SW is more-favorable for improved oil recovery than formation brine because injection of SW after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite on the basis of the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF.
To conclude, this paper demonstrates that LSF has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, further research is required to explore the optimum salinity and composition and the most-influential parameters affecting LSF response.