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.
By coupling heat and mass transfer for C3H8–
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.
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.
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.
Wang, Haitao (Petroleum Exploration & Production Research Institute, Sinopec) | Lun, Zengmin (Petroleum Exploration & Production Research Institute, Sinopec) | Lv, Chengyuan (Petroleum Exploration & Production Research Institute, Sinopec) | Lang, Dongjiang (Petroleum Exploration & Production Research Institute, Sinopec) | Pan, Weiyi (Petroleum Exploration & Production Research Institute, Sinopec) | Luo, Ming (Petroleum Exploration & Production Research Institute, Sinopec) | Wang, Rui (Petroleum Exploration & Production Research Institute, Sinopec) | Chen, Shaohua (Petroleum Exploration & Production Research Institute, Sinopec)
Nuclear magnetic resonance (NMR) was used to investigate the exposure between CO2 and matrix with permeability of 0.218 mD at 40 °C and 12 MPa. Before NMR experiment, the core was saturated with oil. To investigate the effects of exposure time on EOR, the saturated core was exposed to CO2 and T2 test was continuously performed with NMR system until the obtained T2 spectrum was unchanged. After the first exposure, CO2 and matrix reached equilibrium state. The second exposure started when CO2 injection was under a constant pressure of 12 MPa and at a constant rate to keep fresh CO2 in system. The procedure of T2 test was unchanged. The third and fourth exposures were conducted in sequence. The results showed that (1) Oil in all pores can mobilize as exposure time increases. (2) The recovery is 46.6% for oil in pores with the diameter of pore larger than 1 µm, this result is higher than the recovery (12.8%) for oil in pores with the diameter of pore smaller than 1 µm. (3) Recovery can be divided into two stages according to the exposure time: a fast-growing stage and a slow-growing stage. (4) Initially, the oil exists in pores with maximum radius of 21 µm in the originally saturated core. After CO2 injection, oil flows to pores with radius greater than 21 µm, suggesting that oil in tight matrix "diffuses" to the surface of core with exposure between CO2 and matrix. (5) The final recoveries of 1st, 2nd, 3rd, 4th exposure experiments are 23.7%, 7.2%, 2.6% and 1.5%, respectively.
It is generally assumed that while the presence of foam reduces the mobility of the gas phase, it does not alter the mobility of the liquid phase. Here, the effect of surfactant type and concentration on the behavior of nitrogen foam flow in porous media is investigated by simultaneous injection of gas and surfactant into Bentheimer sandstone cores. Different surfactant types, viz., anionic alpha-olefin-sulfonate (AOS) and zwitterionic Betaine with different surfactant concentrations from critical-micelle-concentration (CMC) to higher concentration are used in this study. The foam strength is quantified by measuring the pressure drop in different sections of the core. The liquid saturation is measured by analyzing the X-ray images obtained in a medical CT-scanner.
It is shown that the connate water saturation is reduced by increasing the surfactant concentration, and therefore the relative permeability relation for the aqueous phase should be modified when fitting the data to the foam models. It is observed that it is not possible to fit one monotonic liquid relative permeability curve to all the data points, obtained with different surfactant type and concentration in one rock type. Moreover, increasing AOS concentration above a certain value does not have a significant effect on the mobility reduction of the gas phase; however it modifies the liquid relative permeability. These results indicate that the water relative permeability measured in absence of surfactant should not be used to model the flow of foam in porous media, as it can lead to erroneous calculations of the liquid saturation.
We present a technique that enables the determination of the minimum miscibility pressure (MMP) of a CO2 – oil system using a short 20 ft slim tube in less than two weeks, about a third of what it normally takes using the conventional 80 ft slim tube. MMP is a crucial parameter in designing a CO2 enhanced oil recovery project and its value needs to be known with a degree of accuracy that cannot be provided by the use of equations of state or correlations, and therefore, needs to be determined experimentally. The slim tube technique is recognized to be the most accurate experimental method for determining the MMP, however its use has not been favored because it is time consuming.
We determined the MMP for five CO2 – crude oil systems from the North Burbank Unit and the Oklahoma/Texas Panhandle. The reduction in the length of the slim tube from 80 ft to 20 ft resulted in a decrease in the total time of the experiment. The validity of our technique was proven with performing recovery factor measurements using a conventional 80 ft long slim tube. The MMP values obtained are valid when the length of the slim tube is sufficient to host the mixing zone and the velocity of the displacement is slow enough to enable the transverse dispersion to eliminate viscous fingering. In the case of light oil, the use of the 20 ft slim tube is justified as the length of the mixing zone is shorter. We support our results with the use of numerical simulation.
The reduction in the time required for slim tube experiments results in a fast, economic and accurate technique for the determination of MMP in CO2 – light crude oil systems. Taking into account that CO2 flooding is the most applied EOR technique in the US and that it is mainly applied to light oil reservoirs, this work can be of great impact by providing a rapid and reliable method to determine the MMP for designing a CO2 enhanced oil recovery project.
Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, For this application, hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. In an era of low cost oil, it is becoming even more essential to optimize the polymer flooding design under realistic reservoir conditions. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation, in order to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the water floods, with up to 24% lower oil saturation after the polymer flood than the water flood. The experimental data are in good agreement with the fractional flow analysis using the assumptions that the true residual oil saturations and end point relative permeabilities are the same for both water and polymer. This suggests that for more viscous oils, the oil saturation at the end of water flood (i.e. at greater than 99% water cut) is better described as ‘emaining’ oil saturation rather than the true ‘esidual’ oil saturation. This was true for all of the corefloods regardless of the core permeability and without the need for assuming a permeability reduction factor in the fractional flow analysis.