A systematic approach to characterize the mixed wet configurations of various reservoir rocks (sandstone and carbonates) by evaluating their surface energy distributions has been presented in this paper. This approach was tested against the macroscopic spatial distribution of oil-wet and water-wet sites and at different temperatures for validation.
The new approach used to characterize the mixed wettability of a reservoir rock pertains to establishing a relation between the volume fraction of the mixed-wet reservoir rocks and surface energy of the mixture. This approach is based on an accurate description of the various physico-chemical interfacial forces present at the reservoir rock surface using Inverse Gas Chromatography (IGC). Mixed-wet configurations of various reservoir rocks are created by combining water-wet and oil-wet samples of the rock in different volume fractions and shaken together to establish uniform distribution. These samples are then subjected to the IGC analysis at different temperatures to deduce their surface energy distribution. The relation developed herein is tested against spatial heterogeneity by combining the oil-wet and water-wet rock samples in a layered fashion to validate the approach. The complete method to deduce the surface energy distribution of a rock surface using IGC has also been explained in detail.
A definite and conclusive relationship between the surface energy and mixed wettability of silica glass beads, calcite, and dolomite samples was established in this study. The mixed-wet configurations of the rock samples ranged from 0% oil-wet (meaning water-wet samples) to 100% oil-wet samples. The findings indicated that the Lifshitz-van der Waals component of the rock mixture did not undergo any change with change in the wetting state of the system under study. However the acid base components showed a marked decrease with increasing oil wetness before plateauing. Temperature was found to have a profound impact on the surface energy of a rock surface. Spatial heterogeneity by way of layered and segregated distribution of oil-wet and water-wet sites did not affect the eventual surface energy distribution thereby validating the new approach.
Yao, Chuanjin (China University of Petroleum) | Xu, Xiaohong (China University of Petroleum) | Wang, Dan (China University of Petroleum) | Lei, Guanglun (China University of Petroleum) | Xue, Shifeng (China University of Petroleum) | Hou, Jian (China University of Petroleum) | Cathles, Lawrence M. (Cornell University) | Steenhuis, Tammo S. (Cornell University)
Micron-size polyacrylamide elastic microspheres (MPEMs) are a smart sweep improvement and profile modification agent, which can be prepared controllably on the ground through inverse suspension polymerization using acrylamide crosslinked with an organic crosslinker. MPEMs can tolerate high temperature of 90 °C, high salinity of 20000 mg/L and wide pH value range of 4.0–10.3. MPEMs suspension almost has no corrosion effect on the injection pipeline and equipment. MPEMs can suspend in produced water easily and be pumped into formation at any rate. More importantly, MPEMs can reach the designed size after hydration swelling in oil formation and a reliable blockage can be formed; MPEMs can deform elastically and move forward step by step to realize a moveable sweep improvement and profile modification process in reservoirs. The pore-scale visualization experiment shows that there are four migration patterns for MPEMs transport in porous media and they are smooth passing, elastic plugging, bridge plugging and complete plugging. MPEMs can deform depending on their elasticity and pass through these pore-throats. Parallel-sandpack physical modeling experiment under the simulated reservoir conditions shows that MPEMs mainly enter into and plug high permeability layer whose permeability is reduced from 3.642 µm2 to 0.546 µm2, and almost do not clog low-permeability layer whose permeability is reduced from 0.534 µm2 to 0.512 µm2. Field application results of MPEMs treatment in a serious heterogeneous, high temperature and high salinity reservoir show that MPEMs can effectively improve swept volume and displacement efficiency. Because of the excellent properties, MPEMs treatment will become a cost-effective method for sweep improvement and profile modification to serious heterogeneous, high temperature and high salinity reservoirs with fractures and channels.
Depth to Surface Resistivity (DSR) has been shown to be effective at mapping CO2, water flood, and residual oil aerially and vertically. Provided there is sufficient resistivity contrast between injected and in-situ fluids and subject to the reservoir depth and overburden resistivity, the technique is applicable for monitoring IOR/EOR fields. This information can be used to evaluate cap rock integrity, fluid loss to faults, and migration paths. The following paper presents a study of a CO2 flood followed by water alternating gas (WAG) injection.
Kim, Ijung (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Worthen, Andrew J. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | Lotfollahi, Mohammad (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Johnston, Keith P. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | DiCarlo, David A. (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Huh, Chun (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin)
The immense nanotechnology advances in other industries provided opportunities to rapidly develop various applications of nanoparticles in the oil and gas industry. In particular, nanoparticle has shown its capability to improve the emulsion stability by generating so-called Pickering emulsion, which is expected to improve EOR processes with better conformance control. Recent studies showed a significant synergy between nanoparticles and very low concentration of surfactant, in generating highly stable emulsions. This study's focus is to exploit the synergy's benefit in employing such emulsions for improved mobility control, especially under high-salinity conditions.
Hydrophilic silica nanoparticles were employed to quantify the synergy of nanoparticle and surfactant in oil-in-brine emulsion formation. The nanoparticle and/or the selected surfactant in aqueous phase and decane were co-injected into a sandpack column to generate oil-in-brine emulsions. Four different surfactants (cationic, nonionic, zwitterionic, and anionic) were examined, and the emulsion stability was analyzed using microscope and rheometer.
Strong and stable emulsions were successfully generated in the combinations of either cationic or nonionic surfactant with nanoparticles, while the nanoparticles and the surfactant by themselves were unable to generate stable emulsions. The synergy was most significant with the cationic surfactant, while the anionic surfactant was least effective, indicating the electrostatic interactions with surfactant and liquid/liquid interface as a decisive factor. With the zwitterionic surfactant, the synergy effect was not as great as the cationic surfactant. The synergy was greater with the nonionic surfactant than the zwitterionic surfactant, implying that the surfactant adsorption at oil-brine interface can be increased by hydrogen bonding between surfactant and nanoparticle when the electrostatic repulsion is no longer effective.
In generating highly stable emulsions for improved control for adverse-mobility waterflooding in harsh-condition reservoirs, we show a procedure to find the optimum choice of surfactant and its concentration to effectively and efficiently generate the nanoparticle-stabilized emulsion exploiting their synergy. The findings in this study propose a way to maximize the beneficial use of nanoparticle-stabilized emulsions for EOR at minimum cost for nanoparticle and surfactant.
Sabiriyah Upper Burgan is a clastic reservoir in North Kuwait, under active development through water flooding and ongoing development drilling. The reservoir is one of the most heterogeneous reservoirs in NK, both geologically and with respect to pressure-production performance. There is wide variance in rock & fluid quality laterally and vertically, compounding the development challenges while water flooding.
The crestal portion of the dome-shaped reservoir exhibited a sharp drop in reservoir pressure. As a result of which, Sea Water injection was started at 3 vertical injectors. Surprisingly, the injectivity in 500-1000 md rock was found to be very poor. Well interventions were attempted to improve the injectivity, including a proppant frac. A series of Step rate tests were conducted to understand & evaluate the possibility of injecting above the parting pressure. The wellhead injection pressure requirement was estimated to be about 3700 psia to attain the desired level of injectivity. This was a turning point on the water flooding strategy for the reservoir, as a new project for water flooding was needed with the surface injection pressure capability.
During the preliminary water flood response, it was observed that there were compartments, even 250 ft. away from the injector. In addition, a major part of the mid-flank & lower-flank segments had questionable connectivity. Expansion of water flood was delayed in order to provide sufficient time for data acquisition, interpretation, and analysis, using the sub surface data of all wells penetrating the Upper Burgan. The strategy was to produce and further develop the reservoir with limited drilling of new wells in high pressure channels/segments and adopting Integrated Reservoir Management (IRM) approach. Now the expanded Injection facility is complete, and enhanced injection quantum have been initiated since March 2014. An active surveillance master plan & segment wise review of pressure-production data are under implementation to maximize the benefit of the water flood to this reservoir.
The reservoir response due to water flood has been realized to get 100% production increase with sustainable rates. The pressure sink locales are re-vitalized with indications of pressure increase. The Voidage Replacement Ratio has improved to 1:1 at identified segments (producer-injection combinations) as per channelized architecture. There is indeed a positive response despite a few premature water breakthrough instances in producers located very close to the injectors. The results have led to plan for water flow regulators in injectors so that zonal conformance control can be achieved to improve the areal & vertical sweep. The reservoir simulation model is being updated with all dynamic pressure-production as well as surveillance data so as to optimize the ultimate recovery.
The paper is focused to share the learning curve and the quick adoption of the implementation of actions adhering to the best practice reservoir management.
This paper presents the basic reservoir characteristics and the key improved oil recovery/enhanced oil recovery (IOR/EOR) methods for sandstone reservoir fields that have achieved recovery factors toward 70%. The study is based on a global analog knowledge base and associated analytical tools. The knowledge base contains both static (STOIIP, primary and ultimate recovery factors, reservoir/fluid properties, well spacing, drive mechanism, and IOR/EOR methods etc.) and dynamic data (oil rate, water-cut, and GOR, etc.) for more than 730 sandstone oil reservoirs. These reservoirs were subdivided into two groups: heavy and conventional oil reservoirs. This study focuses on the reservoirs with recovery factors great than 50% for heavy oil, and recovery factors from 60% to 79% for conventional oil with a view to understand the key factors for such a high recovery efficiency. These key factors include reservoir and fluid properties, wettability, development strategies and the IOR/EOR methods.
The high ultimate recovery factors for heavy oil reservoirs are attributed to excellent reservoir properties, horizontal well application, high efficiency of cyclic steam stimulating (CSS) and steam flood, and very tight well spacing (P50 value of 4 acres, as close as 0.25 acres) development strategy. The 51 high recovery conventional clastic reservoirs are characterized by favorable reservoir and fluid properties, water-wet or mixed-wet wettability, high net to gross ratio, and strong natural aquifer drive mechanism. Infill drilling and water flood led to an incremental recovery of 20% to 50%. EOR technologies, such as CO2 miscible and polymer flood, led to an incremental recovery of 8% to 15%. Homogeneous sandstone reservoirs with a good lateral correlation can reach 79% final recovery through water flood and adoption of close well spacing.
The lessons learned and best practices from the global analog reservoir knowledge base can be used to identify opportunities for reserve growth of mature fields. With favorable reservoir conditions, it is feasible to move final recovery factor toward 70% through integrating good reservoir management practices with the appropriate IOR/EOR technology.
Accurate assessment of remaining oil saturation and sweep efficiency greatly depends on the implemented monitoring program, which requires the integration of all available geoscience and engineering data, by effective analysis using statistical and reservoir simulation methods. This will allow improvedunderstanding of sweep, validation of recovery factor and identifying new development opportunities.
Comprehensive reservoir surveillance is also a critical factor for effective reservoir management in achieving optimal hydrocarbon recovery. Monitoring programs encompass the deployment of up-to-date reservoir saturation tools and techniques capable of delivering high-quality data. There are many complications to be considered such as mixed salinity environments, reservoir heterogeneities, tools with limited depth of investigation and mud invasion effects. These challenges must be considered for a successful reservoir saturation monitoring program. Therefore, the value established by an integrated program involves the use of the most efficient approach in analyzing the acquired saturation data and overcoming the field challenges.
This paper presents a comprehensive approach that was implemented on in situ data acquired from a carbonate reservoir that has operated continuously for several decades with pressure support from peripheral water injection. The technique capitalizes on the wealth of data acquired both from saturation and production logs. The prime objectives of this technique are to evaluate remaining oil saturation, remaining unswept oil column and displacement, and vertical/areal sweep efficiency. The strength of this methodology is the capability of efficiently quantifying and mapping remaining oil saturation. This helps in identifying "sweet spots" behind the flood front and thereby guiding future development activities for maximizing hydrocarbon recovery.
Jahanbakhsh, A. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Sohrabi, M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Fatemi, S. M. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University) | Shahverdi, H. (Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University)
Gas/oil interfacial tension (IFT) is one of the most important parameters that impact the performance of gas injection in an oil reservoir. The choice or design of the composition of the gas injected for EOR is usually affected by the gas/oil IFT. In conventional reservoir simulation, IFT does not explicitly appear in the equations of flow and therefore its effect must be captured by the shape and values of relative permeability curves. A few studies have been previously reported for IFT effect on two-phase flow but very little have been done to investigate gas/oil IFT effect under three-phase flow conditions. The objective of this study is, firstly, to investigate the impact of gas/oil IFT reduction on two- and three-phase relative permeabilities using coreflood experiments. Secondly, to investigate the effect of changing gas/oil IFT value (immiscible and near-miscible) on the performance of WAG injections and residual oil saturation reduction at laboratory scale.
Two- and three-phase (WAG) coreflood experiments have been performed on water-wet and mixed-wet cores at three different gas/oil IFT conditions. These experiments were conducted on Clashach sandstone cores with a permeability of 65 and 1000 mD. The two- and three-phase relative permeabilities were estimated from the results of the coreflood experiments using our in-house software (3RPSim) and were compared with each other on the basis of their gas/oil IFT values. Moreover, the impact of gas/oil IFT reduction on the performance of gas and WAG injection and in particular on the reduction of residual oil saturation was investigated. The results of our studies were also compared with the existing literature on the laboratory investigation of WAG injection.
The results show that in two-phase gas/oil systems, the relative permeability of non-wetting phase is more affected by a reduction in the gas/oil IFT compared of the relative permeability of the wetting phase. Comparing the curvature of the gas and oil relative permeability curves shows that although the curvature decreases by a reduction in gas/oil IFT but it is still far away from straight line even at ultra-low IFT values. In three-phase flow system, reduction of gas/oil IFT affects the relative permeabilities of all the three phases (gas, oil and water).
The results show that at high gas/oil IFT or immiscible WAG injection, the most reduction in residual oil saturation is achieved in the first injection cycle and further WAG cycles do not result in a significant additional reduction in oil saturation. On the contrary, at low gas/oil IFT or near-miscible WAG injection, the residual oil saturation keeps decreasing as the number of WAG cycles increases. Moreover, the reduction in residual oil saturation was more effective when the immiscible WAG experiments started with gas injection (secondary WAG).
This paper describes the analysis and positive results of injecting water, from constant to discontinuous rates in a reservoir under a high water cut stage. By following and improving waterflooding surveillance applications it was possible not only to describe the kind of reservoir, but also to keep the water cut up for a longer time. The goal of this study is to demonstrate the powerful benefits of applying and improving the surveillance plots that are available in the existing literature. The pore volumes injected plot, which was enhanced in this study by adding the injection rates per well in a secondary Y axis, was a powerful tool to identify the water cut behavior.
One of the two injector wells of the field was shut in for about 5 months and returned to its water injection conditions for 7 months. These events are presented in three phases. The first is related to the reservoir characterization achieved before the injector shut in. The second includes the well responses observed and monitored during the injector shut in. And, the third illustrates the promising reservoir results after the injector shut in. As well, an economic model is also developed.
As a result of the field events, analysis, and results described in this paper, the reservoir water cut was stable for a longer time in comparison with the whole life of the IOR project. In addition the increase Estimate Ultimate Recovery was 304,968 bbl for 8 years, the net present value of the field increased to 24%, and the average operating cost was reduced to 2.49 USD/bbl from 2015 to 2022.
The cyclic waterflooding existing literature supports reservoir characterization, analysis and results achieved in Tiguino Field. The initial application monitored in Ecuador will be helpful to be considered as a first approach for starting an IOR optimization in similar stratified reservoirs. The results obtained in Tiguino field are helpful not only as a real example but also as a statistical support for cyclic waterflooding. The Tiguino case experience would be extrapolated to other fields worldwide.
It is now common knowledge among EOR practitioners that the combination of ferrous iron (Fe2+) and oxygen causes severe oxidative degradation to EOR polymers, resulting in a lowering of molecular weight and hence a loss of viscosity. During the design of polymer flooding projects, an important question is thus the acceptable levels of Fe2+ and dissolved oxygen that can be tolerated in injection water specifications. Furthermore, we would like to be able to predict the extent of degradation in the case of excess Fe2+ or oxygen ingress.
However, despite over fifty years of research and a general understanding of the degradation mechanism involved, quantitative prediction of the extent of degradation has proven elusive and dependent on the measurement protocol. This is likely due to the fastidious experimental protocols required to work under anaerobic or limited-oxygen conditions.
We examine existing protocols and demonstrate that experiments in which either Fe2+ or oxygen are the limiting reagent yield equivalent results when the stoechiometry of the Fe2+ oxidation reaction with oxygen is taken into account. Based upon these findings, a novel, easy approach is proposed to quantify polymer oxidative degradation as a function of either dissolved oxygen or Fe2+ content.
The limits of 225 ppb Fe2+ and 32 ppb dissolved oxygen are fixed for Flopaam 3630S in 6 g/l brine in the concentration range 500-1500ppm in order to ensure degradation of low-shear plateau viscosity does not exceed 10%. Higher levels will lead to severe polymer degradation. The influence of polymer concentration, temperature and salinity is also investigated. At last, evolution of redox potential and pH during Fe2+ oxidation are discussed.
There is a direct practical application of these finding for the design of surface facilities for polymer dissolution and transport and for the prediction of degradation in case of oxygen ingress. Moreover, a simple and easily performed protocol is proposed for the evaluation of polymer oxidative degradation.