Fatehgarh reservoirs in Aishwariya field, located in Barmer Basin of Rajasthan India, have very high CO2 content in reservoir fluid. A procedure was developed earlier to model the impact of reservoir CO2 on waterflood, polymer flood and ASP flood (
The objective of this work was to validate the modelling procedure developed to predict the produced gas rate in such a system with very high amount of CO2 in reservoir fluid.
A live oil coreflood experiment was carried out using 12 inches long Bentheimer core under Aishwariya reservoir pressure and temperature conditions. After saturating the core with live oil, the core was water flooded with brine for ~3.7 pore volumes. Produced gas volume was measured at different times so as to generate gas production profile.
Two different simulation techniques were used to simulate the experiment and match the gas production profile. First technique was using a compositional simulator with EOS based PVT while the other technique was using an "advanced processes simulator" modeling the component distributions based on partitioning coefficients. Both methods could successfully capture the production of gas from both liquid streams; oil and water and a reasonable match for the produced gas could be obtained.
The approach developed to simulate impact of CO2 on different aqueous based flooding processes in Aishwariya field was validated by matching the coreflood experiment carried out under actual Aishwariya reservoir conditions. It helped to confirm confidence in performance prediction of aqueous based flooding mechanisms planned in Aishwariya field despite the presence of significant amount of CO2.
The paper presents history match of unconventional produced gas profile of a coreflood carried out under Aishwariya field conditions with very high amount of dissolved CO2. The proposed method can be applied to estimate produced gas rate in other fields with very high amount of CO2 in reservoir fluid.
It has been demonstrated in both laboratory measurements and field applications that tertiary polymer flooding can enhance oil recovery from heterogeneous reservoirs, primarily through macroscopic sweep (conformance). This study quantifies the effect of layering on tertiary polymer flooding as a function of layer-permeability contrast, the timing of polymer flooding, the oil/water-viscosity ratio, and the oil/polymer-viscosity ratio. This is achieved by analyzing the results from fine-grid numerical simulations of waterflooding and tertiary polymer flooding in simple layered models.
We find that there is a permeability contrast between the layers of the reservoir at which maximum incremental oil recovery is obtained, and this permeability contrast depends on the oil/water-viscosity ratio, polymer/water-viscosity ratio, and onset time for the polymer flood. Building on an earlier formulation that describes whether a displacement is understable or overstable, we present a linear correlation to estimate this permeability contrast. The accuracy of the newly proposed formulation is demonstrated by reproducing and predicting the permeability contrast from existing flow simulations and further flow simulations that have not been used to formulate the correlation.
This correlation will enable reservoir engineers to estimate the combination of permeability contrast, water/oil-viscosity ratio, and polymer/water-viscosity ratio that will give the maximum incremental oil recovery from tertiary polymer flooding in layered reservoirs regardless of the timing of the start of polymer flooding. This could be a useful screening tool to use before starting a full-scale simulation study of polymer flooding in each reservoir.
Huang, Hai (Xi'an Shiyou University, Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Babadagli, Tayfun (University of Alberta) | Chen, Xin (University of Alberta) | Li, Huazhou (University of Alberta)
Tight sands are abundant in nanopores leading to a high capillary pressure and normally a low fluid injectivity. As such, spontaneous imbibition might be an effective mechanism for improving oil recovery from tight sands after fracturing. The chemical agents added to the injected water can alter the interfacial properties, which could help further enhance the oil recovery by spontaneous imbibition. This study explores the possibility of using novel chemicals to enhance oil recovery from tight sands via spontaneous imbibition. We experimentally examine the effects of more than ten different chemical agents on spontaneous imbibition, including a cationic surfactant (C12TAB), two anionic surfactants (O242 and O342), an ionic liquid (BMMIM BF4), a high pH solution (NaBO2), and a series of house-made deep eutectic solvents (DES3-7, 9, 11 and 14). Experimental results indicate that the ionic liquid and cationic surfactant used in this study are detrimental to spontaneous imbibition and decrease the oil recovery from tight sands. The high pH NaBO2 solution does not demonstrate significant effect on improving oil recovery, even though it significantly reduces oil-water interfacial tension (IFT). The anionic surfactants (O242 and O342) are effective in enhancing oil recovery from tight sands through oil-water IFT reduction and emulsification effects. The DESs drive the rock surface to be more water-wet and a specific formulation (DES9) leads to much improvement on oil recovery under counter-current imbibition condition. This preliminary study would provide some knowledge about how to optimize the selection of chemicals for improving oil recovery from tight reservoirs.
Al Kalbani, M. M. (Heriot-Watt University) | Jordan, M. M. (Nalco Champion) | Mackay, E. J. (Heriot-Watt University) | Sorbie, K. S. (Heriot-Watt University) | Nghiem, L. (Computer Modelling Group Ltd.)
Barium Sulphate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing water flooding. Chemical Enhanced Oil Recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulphate co-production behaviour, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer (P), surfactant (S) and surfactant-polymer (SP) flooding cEOR processes.
Reservoir simulation has been used in this study, employing homogenous and heterogeneous 2D areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of surfactant and polymer (e.g. oil-water interfacial tension, IFT, polymer viscosity and surfactant and polymer adsorption). Assessment is made of the minimum inhibitor concentration (MIC) required to control scale that is predicted to occur due to changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor during squeeze treatments in the production wells is modelled.
The high viscosity and more stable polymer slug reduces the mixing between the injected and the formation brines, reducing BaSO4 scale precipitation in the formation and delaying the potential scale risk in the producer wellbore compared to normal water flooding. Polymer adsorption causes retardation of the polymer front compared to the sulphate front, accelerating the scale risk in the wellbore. Polymer with low salinity make-up brine and low sulphate concentration not only improves polymer viscosity and enhances recovery, it also delays and reduces the scale risk in the formation and the producer. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the water flooding case, depending on the IFT, ME phase type, the injected salinity and sulphate concentration. In SP flooding, low salinity make-up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the changing brine composition due to ion reactions affected the required MIC values over time. The impact of the MIC and salinity changes on inhibitor retention and release then influences the treatment volumes required to control scale over field life.
The study shows that barium and sulphate co-production and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities), on the oil-water IFT and on the level of chemical adsorption. The severity of the scale risk is also impacted by the flood techniques utilised, with the extent of reservoir reactions have an effect on the MIC required to control scale and the squeeze treatment volumes required to maintain production after breakthrough.
Rahayyem, Maher (Saudi Aramco) | Mostaghimi, Peyman (School of Minerals and Energy Resources Engineering, The University of New South Wales) | Alzahid, Yara A. (School of Minerals and Energy Resources Engineering, The University of New South Wales) | Halim, Amalia (School of Minerals and Energy Resources Engineering, The University of New South Wales) | Evangelista, Lucas (Biotech Processing Supply, LLC) | Armstrong, Ryan T. (School of Minerals and Energy Resources Engineering, The University of New South Wales)
Enzyme Enhanced Oil Recovery (EEOR) has recently been categorized as one of the most effective EOR mechanisms. Laboratory and field studies have reported up to 16% of incremental oil recovery rates. EEOR recovers oil mainly by two main mechanisms: lowering the interfacial tension between brine and oil and altering the wettability on rock grains to a more water-wet condition. Therefore, EEOR would promote mobilization of capillary-trapped oil after regular waterflooding. Since capillary-trapped oil resides at the micro-scale, it is essential to assess EEOR fluid-fluid interaction at that scale. To further investigate the ways in which these enzymes contribute to EOR, an experimental micro-scale approach was developed in which EEOR was analyzed using polydimethylsiloxane (PDMS) microfluidic devices. The PDMS microfluidics device was based on X-ray micro-CT images of a Bentheimer sandstone with resolution of 4.95 μm. We first compared the IFT reduction capabilities of one class of enzyme (Apollo GreenZyme ®) and a commercial surfactant (J13131) obtained from Shell Chemicals. For GreenZyme concentrations of 0.5, 1.5 and 2 wt%, the IFT values between GreenZyme solution and oil are 4.2, 0.7 and 0.6 mN/m, respectively. Whereas the IFT values for 0.5 wt% surfactant solutions and deionized water are 1.1 and 32 mN/m, respectively. We then compared the oil recovery of the two systems using the aforementioned sandstone PDMS microfluidics device. Recovery values up to 92% of oilwere obtained using GreenZyme. Surfactant and waterflooding on the same PDMS chips had recovery values of 86 and 80%, respectively. This study provides insights and direct visualization of the micro-scale oil recovery mechanisms of EEOR that can be used for design of effective EEOR flooding.
Chemicals in oil fields have shown a great potential for enhancing/improving oil recovery (EOR/IOR) beyond waterflood baseline. The objectives of this work are: (1) to develop a cost-effective method to deliver chemicals to deeper layers in reservoirs compared to conventional chemical operations, (2) to synthesize nano-capsules with improved stability under typical reservoir temperatures (80-110 °C), and (3) to demonstrate the gradual release of EOR/IOR chemicals over time at a given temperature within the above range. Multiple slow-release technologies were developed; (1) Nano-salt (2) liposomes and (3) nano-capsules. In the first method, nano-size surfactant salt particle that has a limited solubility can traverse the reservoir and deliver, over a long period of time, a constant concentration of surfactant was synthesized. In addition to surfactant salts, surfactant-loaded nano-capsules were synthesized by dissolving a known lipid formula in 20.0 mL chloroform, then, evaporating the solvent to form a dried lipid film. Acid nano-capsules for improving oil recovery operations were synthesized using In situ and interfacial polymerization. Scanning electron microscopy, an optical microscopy, dynamic light scattering, Inductive coupled plasma (ICP-AES), pH and surfactant electrodes were used to characterize the nano-capsules and dispersion. To assist the nano-platforms slow-release profile and the particles stability under reservoir conditions, the samples were incubated in oven at 95 °C. The nano-capsules’ slow-release and stability were monitored for several days. The liposomes contain 11 wt. % of PETRONATE® EOR2095 with particles’ average size of ~80 nm, the surfactant released was gradually increased over sixty hours. The acid nano-capsules contain 15 wt. % acid precursor with particles’ average size of 200 nm. The capsules release versus time curve showed that the release occurred when the temperature reached 95 °C, indicating that nano-capsules’ release is triggered by the temperature increment. The pH versus time release curve exhibits a gradual decreasing in the pH over six day indicating the acid precursor hydrolysis at 95 °C. Our results demonstrate the possibility of improving current chemicals flood via nano-encapsulation. The slow release technology may bring new potentials to the current hydrocarbon production operations.
Lu, Xiaoguang (C&C Reservoirs) | Xu, John (C&C Reservoirs) | Feng, Lijing (N0. 4 Oil Production Company, Daqing, PetroChina) | Yang, Qing (C&C Reservoirs) | Li, Guoqiang (C&C Reservoirs) | Lin, Lihua (C&C Reservoirs)
The XB Field in China contains more than 100 thin sand units deposited in a non-marine environment, which results in an extremely heterogeneous sandstone reservoir. Comparison with global field analogs of similar reservoir characteristics indicates that the >60% ultimate recovery in the XB Field is much higher than average. This paper reviews the over 50 years of production history and summarizes its development strategies, successful reservoir management practices, key IOR/EOR technologies and lessons learned, which can benefit efforts of maximizing recovery in other reservoirs.
This paper begins by summarizing the basic reservoir and fluid characteristics as well as the production performance history. This is followed by a benchmarking analysis focused on reservoir heterogeneity, fluid properties and recovery factor against global analog reservoirs. Finally, the authors highlight the development strategy, key IOR/EOR methods, and integrated reservoir management practices based on fit-for-purpose reservoir and remaining oil characterization studies.
The benchmarking study against global analogs shows the XB reservoir to possess much higher heterogeneities and poorer fluid properties than average. The field is expected to achieve an ultimate recovery of more than 60%, which is substantially higher than the average of 36.7% and P50 value of 36% based on global reservoir analog in C&C Reservoirs DAKS. The key IOR methods applied include pressure maintenance through water injection starting at early development stage, infill drilling, and chemical EOR methods. Water injection and infill drilling have helped improve recovery by 30% and 20%, respectively. Water injection optimization has been applied throughout the 50-year production history, focused on by-passed oil or poorly swept areas. Zonal water injection, subdivision of injecting-producing unit, modification injection pattern and cyclic water injection are methods of this category. Other IOR methods, such as horizontal well targeting by-passed oil, profile modification, and fracturing of low permeability reservoir sands also contribute to the high recovery factor. When the field entered the mature production stage, field-wide polymer and ASP flooding have been implemented based on numerous laboratory studies and pilot tests. The chemical EOR application in this field is one of the most successful cases in the world. Polymer flood and ASP flood are expected to achieve incremental recovery factor of 10% and 20%, respectively.
The XB Field case suggests that many mature fields in the globe have the potential to further improve their recovery. Most of the technologies discussed in this paper are well established, conventional, inexpensive and readily available. The key point is that detailed reservoir characterization, remaining oil identification and application of lessons learned from global analogs are of prime importance.
AlSofi, Abdulkareem M. (Saudi Aramco) | Wang, Jinxun (Saudi Aramco) | AlBoqmi, Abdullah M. (Saudi Aramco) | AlOtaibi, Mohammed B. (Saudi Aramco) | Ayirala, Subhash C. (Saudi Aramco) | AlYousef, Ali A. (Saudi Aramco)
The synergy between various enhanced-oil-recovery (EOR) processes has always been raised as a potential optimization route for achieving a more-economic and more-effective EOR application. In this study, we investigate the possible synergy between polymer and smartwater flooding for viscous-oil recovery in carbonates. Although the potential for such synergy has been suggested and researched in the literature, we investigate this possibility in a more-realistic framework: part of the development of an EOR portfolio for a slightly viscous Arabian heavy-oil reservoir. In this work, we study the possible synergy between smartwater and polymer flooding by performing rheological, electrokinetic potential (ζ-potential), contact-angle, interfacial tension (IFT), and recovery experiments.
Rheological tests, as expected, demonstrated the possibility of achieving the same target viscosity at lower polymer concentrations. With smartwater, the polymer concentration required to achieve a target viscosity of 11 mPas was found to be one-third lower than that with normal high-salinity injection water. Electrokinetic-potential and contact-angle results demonstrated that polymer presence has negligible to slightly favorable effect on wettability alteration induced by smartwater. On synthetic calcite surfaces, polymer showed negligible effect, whereas on reservoir-rock surfaces, polymer resulted in further reduction in contact angles beyond that obtained with smartwater.
Coreflooding experiments conducted at reservoir conditions with finite smartwater/polymer slugs—besides yielding comparable performance to surfactant/polymer flooding—demonstrated the enhanced performance of smartwater/polymer compared with either of these individual processes. A combined smartwater/polymer process was able to recover substantial additional oil—6.5 to 9.9% original-oil-in-core (OOIC)—above that obtained with either of the two processes when applied independently. Ultimate recoveries from the application of smartwater/polymer (70% OOIC) were quite comparable to, and actually slightly higher than, that of surfactant/polymer (67% OOIC). However, in terms of the remaining oil in core (ROIC) after polymer flooding, both processes (smartwater/polymer and surfactant/polymer) exhibited quite similar incremental recoveries of 20.6 and 20.5% OOIC, respectively.
The results of this work clearly demonstrated the potential synergy between smartwater and polymer flooding—beyond that of the well-established polymer-viscosity enhancement—for a realistic scenario. The additive effect of smartwater was successfully shown to combine with polymer to increase oil recovery, in addition to lowering the polymer concentration. This favorable synergy will reduce chemical-consumption costs and improve recovery to enhance EOR-project economics.
Zhu, Daoyi (China University of Petroleum, Beijing) | Hou, Jirui (China University of Petroleum, Beijing) | Wei, Qi (China University of Petroleum, Beijing) | Chen, Yuguang (China University of Petroleum, Beijing)
The PG Reservoir in Jidong Oil Field is at a depth of approximately 4500 m with an extremely high temperature of approximately 150°C. The average water cut has reached nearly 80%, but the oil recovery is less than 10% after only 2 years of waterflooding process. It is of great importance to develop a high-temperature-resistant plugging system to improve the reservoir conformance and control water production. An in-situ polymer-gel system formed by the terpolymer and a new crosslinker system was developed, and its properties were systematically studied under the condition of extremely high temperature (150°C). Suitable gelation time and favorable gel strength were obtained by adjusting the concentration of the terpolymer (0.4 to 1.0%) and the crosslinker system (0.4 to 0.7%). An increase of polymer and crosslinker concentration would decrease the gelation time and increase the gel strength. The gelant could form continuous 3D network structures and thus have an excellent long-term thermal stability. The syneresis of this gel system was minor, even after being heated for 5 months at the temperature of 150°C. The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. Core-flow experiments showed that the gel system could have great potential to improve the conformance in Jidong Oil Field.
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Hassan, Abrahim Abdelgadir (Kuwait Oil Company) | Al-Ajmi, Naser Ammash (Kuwait Oil Company) | Wartenberg, Nicolas (Solvay) | Delbos, Aline (IFPEN) | Suzanne, Guillaume (Beicip-Franlab)
There are ongoing efforts to assess the techno-ecnomic viability of surfactant polymer (SP) flooding to increase oil recovery by improving microscopic and macroscopic sweep efficiency. This paper sheds light on a methodology to design an appropriate SP formulation for potential deployment in the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait.
Besides achieving low residual oil saturation due to SP flooding under typical RQLF reservoir conditions, this study focuses on mitigating surfactant retention. Several injection strategies were investigated using alkali, adsorption inhibitors and a variety of water treatment techniques. For each scenario, a specific SP formulation was designed and evaluated through static adsorption tests using crushed reservoir rock. The two most promising options were then evaluated through coreflood experiments. The best option was selected based on in-depth chemical propagation, oil desaturation and surfactant adsorption. Finally, lab-optimization work was performed through additional corefloods to reduce chemical consumption while maintaining favorable oil recovery.
Softened seawater obtained through reverse osmosis was considered as the most appropriate water source to implement the desired SP process. Previous work revealed that the use of unsoftened seawater results in high levels of surfactant adsorption on reservoir rock. Salt addition allows applying an efficient salinity gradient post SP injection. Sodium chloride was used instead of alkali which did not exhibit any benefit in this case. A particular effort was made to reduce the amount of added salt and the corresponding formulation cost. Several injection sequences were investigated to compare polymer and SP flooding. The final coreflood experiment based on SP injection (0.6 PV of surfactant at 4 g/l), followed by a salinity gradient, and involving a polymer drive recovered 80% of the original oil in place. The promising performance of this injection sequence will be further evaluated using the results from a one-spot EOR pilot.
This EOR study on the RQLF shallow heavy oil reservoir in Kuwait provides important insights to select an appropriate surfactant-polymer injection strategy to increase oil recovery while maintaining reduced adsorption levels, thereby improving SP techno-economic viability.