An important factor during the life of a heavy crude reservoir is the oil mobility. It depends on two factors, oil viscosity and oil relative permeability. Two characteristics of nanoparticles that make them attractive for assisting IOR and EOR processes are their size (1 to 100 nm) and ability to manipulate their behavior. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the surface of the particle, indicating an increasing in surface energy. Nanoparticles are also able to flow through typical reservoir pore spaces with sizes at or below 1 micron without the risk to block the pore space. Nanofluids or "smart fluids" can be designed by tuning nanoparticle properties, and are prepared by adding small concentrations of nanoparticles to a liquid phase in order to enhance or improve some of the fluid properties. However the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present the field evaluation of nanofluids for improving oil mobility and mitigate alteration of wettability in two Colombian heavy oil fields; Castilla and Chichimene. Asphaltenes sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil based nanofluid (OBN) containing these nanoparticles was evaluated as viscosity reducer under static conditions. Displacement tests through a porous media in core plugs from Castilla and Chichimene at reservoir conditions were also performed. OBN was evaluated to reduce oil viscosity varying oil temperature and water content. Maximum change in oil viscosity is achieved at 122°F and 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests, caused by the removal of asphaltenes from the aggregation system, reduction of oil viscosity, and the effective restoration of original core wettability. Two field trials were performed in Castilla (CNA and CNB wells), by forcing 200 bbl and 150 bbl of nanofluid respectively as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 270 bopd in CNA and 280 bopd in CNB and BSW reductions of ~11% were observed. In Chichimene also two trials were performed (CHA and CHB), by forcing 86 bbl of and 107 bbl of nanofluid as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 310 bopd in CHA and 87 bopd in CHB were achieved not BSW reduction has been observed yet. Interventions were performed few months ago and long term effects are still under evaluation. Results look promising making possible to think extending application of nanofluid in other wells in these fields.
Oglesby, Kenneth D. (Impact Technologies LLC) | D'Souza, David (Denbury Resources) | Roller, Chad (MidCon-Energy Partners LP) | Logsdon, Ryan (MidCon-Energy Partners LP) | Burns, Lyle D. (Clean Tech Innovations, LLC) | Felber, Betty J. (EOR Consultant)
Field test results of a new silicate based Silicate-Polymer-Initiator (SPI) gel system for zonal conformance control are presented from: 3 treatments in a central Mississippi sandstone carbon dioxide (CO2) flood, including 1 producer; 5 injector treatments in a mature, west Texas San Andres dolomite, CO2 flood under Water-Alternating-Gas (WAG) operation; and 2 injector treatments in a northeast Oklahoma waterflood. Gel treatment volumes ranged from 130 to 4,349 barrels of the patented, environmentally friendly, silicate gel system that is pumped at a near water viscosity and density. That pre-gel liquid is triggered to a gel by a pH change caused by external or internal initiation methods. One unique aspect of these silicate solutions is that they can be initiated by both the pre- and post-treatment injected CO2 itself. Alternately, other external and internal initiators can be used in both CO2 and water-floods. Targeted gel times ranged from 1 hour up to 6 days, with maximum gel strength generated within 2–4 weeks. The resultant silicate gels are 10 times stronger than any known gelled polymer system, per CTI laboratory Extrusion and Penetrometer testing. Selected additives were utilized in the gel treatment fluids to focus the pre-gelled solutions into the desired high permeability zones. Furthermore, pre-gel fluid entry into water or oil zones will not set the silicate gel, but will instead dilute the leading edge.
Rate, pressure, injectivity and downhole profile surveys were used to evaluate the treatment in injection wells. Oil, water and gas rates, Water: Oil Ratios, Gas: Oil Ratios and CO2 utilization efficiency were used to evaluate treatments in production wells. Offset production wells were monitored, where possible, for production changes, sometimes seen outside the prior established patterns. Where the data was available, the new silicate gel field treatments were directly compared to prior polyacrylamide and similar conformance systems. In most cases, the new silicate system exhibited positive responses while previous polymer based systems did not respond.
Wu, Xingcai (Research Inst. of Petroleum E&D, RIPED, CNPC) | Yang, Zhongjian (Qinghai Oilfield Company, QOC, CNPC) | Xu, Hanbing (RIPED) | Zhang, Lihui (QOC) | Xiong, Chunming (RIPED) | Yang, Huazhen (Huabei Oilfield Company, HOC, CNPC) | Shao, Liming (RIPED) | Kang, Bo (Chengdu North Petroleum E&D Technology Co. Ltd.) | Fu, Yaxiu (HOC) | Tian, Xiaoyan (Startwell Energy Co. Ltd) | Cao, Huiqing (HOC)
Though polymer flooding is widely considered as a good EOR method for heterogeneous fields, it's always a difficulty to be applied in high temperature and high salinity reservoirs, limited by polymer property. GS-E31 reservoir in West China has ultra-high temperature, 258.8°F (126°C), and ultra-high salinity, 18×104mg/L. It is highly heterogeneous, developed with flowing channels. Starting in July 2012, a new polymer (SMG) flooding was pilot tested, with success technically and economically.
Before SMG injection, tracer test was conducted in the pilot, figuring out the distribution position and direction of prevailing flowing channels. The microscopic pore structure and size were studied. The temperature and salinity resistance of the new particle-type polymer under reservoir condition was tested. The oil displacing effect was simulated on parallel dual core model. For the pilot test, two slugs with different particle sizes were designed. To guarantee the flooding effect, a preposed PPG (preformed particle gel) slug with larger size was designed to inhibit prevailing flow channels.
The lab studies showed the new polymer particles kept stable appearance within 100 days under the reservoir temperature and salinity, denoting high capacity of temperature and salinity resistance. And by physical simulation it could obtain EOR of 12.3%. The pilot test was started in July 2012 and ended in December 2013, and the total liquid injection amount was 12.2×104m3, which was 0.1 PV. During operation, the polymer particle size and concentration were adjusted based on the observing data. As a result, the monthly oil rate of the pilot was increased from 1313 t to 2049.6 t, with increase of 736.6 t; and the water cut was decreased from 91.7% to 84.1%. The cumulative oil incremental was 1.03×104t, and the cumulative water production decrease was 4.79×104m3. The input-output ratio was 1:2.09. Though the economical result was not ideal, it was still acceptable under such severe reservoir conditions. Besides, the surveillance showed the preposed channeling inhibition slug did not perform well, which affected the NPF effect, and especially led to the quick water cut rising in the follow-up water injection phase.
Summarizing the lat studies and pilot tests, the new particle-type polymer has obtained a large breakthrough for temperature and salinity resistance comparing to traditional polymer, and the EOR mechanism is different. The matching relationship between particle size and formation pore size is very important for polymer flooding effect. To further study on lab evaluation method and plan optimization is needed. The technology has important referencing meaning for efficiently developing high temperature and high salinity fields.
Qiu, Yue (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Geng, Jiaming (Missouri University of Science and Technology) | Wu, Fengxiang (Daqing Xinwantong Chemical Co. Ltd.)
This paper presents the detailed descriptions of successful field application for a high-temperature and high-salinity resistance microgel in a mature reservoir in the northwest part of China. The reservoir with low permeability (230 md) experienced serious vertical and lateral heterogeneity problems, which caused low sweep efficiency and high water-cut (more than 95%). The treatment was designed based on laboratory experiments and experience from previous field application, providing detailed information of mechanism of microgel treatment and project execution. Thermal stability test showed that the microgel could resist the salt concentration up to 230,000 ppm at 125 °C for more than 1 year. From the core analysis, permeability of the long-term water-flooded zone was measured around 1,489 md, proving the evidence that high-permeability zones existed. Pilot test has been done before field application and valuable experience about how to design the injection parameters was provided. According to the information from laboratory experiments and the pilot test, four injection wells associated with nine offset production wells were selected for microgel treatment. For about 10 months treatment, 169 t of microgel was injected by five slugs.
Gradually increased injection pressure suggested that microgel could be placed deeply into the reservoir. The ultimate incremental oil production was approximately 29,635.8 t with the water cut decreasing from 95.3% to 93.1%. Microgel can be successfully used in relative low permeability (230 md) reservoir with harsh conditions for conformance control.
Dalmazzone, C. (IFP Energies Nouvelles) | Mouret, A. (IFP Energies Nouvelles) | Behot, J. (IFP Energies Nouvelles) | Norrant, F. (IFP Energies Nouvelles) | Gautier, S. (IFP Energies Nouvelles) | Argillier, J.-F. (IFP Energies Nouvelles) | Chabert, M. (SOLVAY)
A majority of the worldwide oil reserves is contained in carbonate reservoirs. Most of these reservoirs are naturally fractured and produce less than 10% of the oil in place during the primary recovery operations. It is noteworthy that this particularly low recovery ratio is essentially due to a low permeability associated to an intermediate or preferentially oil wettability. Consequently, the recovery of residual oil from these specific reservoirs is a great challenge. Changing the wettability from oil wet to preferentially water wet by using chemicals is one of the EOR technique that may be advantageously used to enhance the production rate. This chemical treatment consists in injecting an aqueous solution of surfactants or chemical additives to increase the water wettability and favour spontaneous imbibition into the porous matrix. We present a new test allowing a fast screening of aqueous solutions of chemicals that may be used to improve oil recovery from carbonate reservoirs. The test consists in depositing a drop of aqueous solution on a porous carbonate slice that has been treated to be preferentially oil wet before being put into dodecane. The evolution of the drop profile is then monitored as a function of time by means of a camera, which permits a simultaneous measurement of the interfacial tension between oil and water, contact angle between the water drop and the porous matrix and spontaneous imbibition. Various types of non-ionic and anionic surfactants belonging to different families have been tested and ranked to identify the best candidates among these chemicals. Finally, a Nuclear Magnetic Resonance technique was used to follow spontaneous imbibitions of selected candidates in miniplugs representative of the carbonate slices used in the screening test. NMR's results confirmed the classification issued from the fast screening test.
Production from tight formation resources leads the growth in U.S. crude oil production. Compared with chemical flooding and water flooding, gas injection is a promising EOR approach in shale reservoirs. A limited number of experimental studies concerning gas flooding in the literature focus on unconventional plays. This study is a laboratory investigation of gas flooding to recover light crude oil from nano-permeable shale reservoirs.
In this work, the N2 flooding process was applied to Eagle Ford core plugs saturated with dead oil. To investigate the effects of flooding time and injection pressure on the recovery factor, two groups of core-flood tests were performed. In group one, flooding time ranged from 1 to 5 days in increments of 1 day; in the other group, the injection pressure ranged from 1,000 psi to 5,000 psi in increments of 1,000 psi. The experimental setup was monitored using X-ray CT that helped to visualize phase flow and estimate the recovery efficiency during the test.
The potential of N2 flooding for improving oil recovery from shale core plugs was examined, and the recovery factor (RF) of each case was presented. The results from group one showed that more oil was produced with a longer flooding time. However, the incremental RF decreased with the increase of flooding time. The oil recovery was significant at the initial period of the recovery process, and a longer flooding time had less effect on extracting more oil. With flooding time constant in 1-day, the results from the second group indicated that RF increased with injection pressure, especially rising pressure, from 1,000 psi to 2,000 psi. The gas breakthrough time became shorter with the increase of injection pressure. The analysis of the CT number showed that the oil recovery process mainly occurred before the gas breakthrough. Once a fluid flow path was established, the injected gas flowed through the limited communication channels; thus, no extra oil could be extracted without increasing the injection pressure. This experimental study illustrates that gas flooding has liquid oil production potential in shale reservoirs.
Rohilla, Neeraj (TIORCO, a Nalco Champion Company) | Ravikiran, Ravi (Stepan Company) | Carlisle, Charlie T. (Chemical Tracers Inc.) | Jones, Nick (University of Wyoming) | Davis, Marron B. (Sunshine Valley Petroleum Corporation) | Finch, Kenneth B. H. (TIORCO, a Nalco Champion Company)
Sandstone reservoirs containing significant amount of clays (30-40 wt%) with moderate permeability (20-50 mD) provide a unique challenge to surfactant based enhanced oil recovery (EOR) processes. A critical risk factor for these types of reservoirs is adsorption of surfactants due to greater surface area attributed to clays. Clays also have high cation exchange capacity (CEC) and can release significant amounts of di-valents that lead to increased retention of the surfactant. These factors could adversely affect the economics of a flood.
We present a case study where a robust formulation was designed and tested in lab/field for a reservoir located in Wyoming, USA and contains up to 35-40 wt% clays (predominately Kaolinite and Illite). The residual oil saturation is high (Sor=0.4) while the permeability of the formation is between 20-50 mD. The reservoir has been waterflooded historically with low salinity water which has led to formation permeability damage. Due to high levels of clays, adsorption of the surfactant on the rock surface was determined to be between 3-4 mg/g rock by static adsorption tests.
This publication demonstrates how the following challenges have been successfully addressed in the lab as well as in the field in the form of single well chemical tracer test (SWCTT).
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity. Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation. Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine. Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front. Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity.
Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation.
Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine.
Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front.
Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
Three-phase relative permeability can vary greatly from two-phase relative permeability as mechanisms such as flow coupling, double displacement, and layer drainage flow regime play a role in three-phase flow. These are on top of the dependency of three-phase relative permeability on two saturations and saturation path/history. The net result is that it is difficult to model/predict relative permeabilities in three-phase space. In this work, we present three-phase oil relative permeability data measured along 11 saturation paths, in a water-wet consolidated (Berea sandstone) and unconsolidated (sandpack) porous media. These saturation paths cover a wide swath of the three-phase saturation space, providing a better physical understanding of the complete three-phase phase space. Three different oils (crude oil, mineral oil, and n-octane) are used in the experiments; the varying viscosities, spreading coefficients, and composition of the oils allows us to investigate the effect of different drainage mechanisms on relative permeability curves. Our data show that there are significant variations between the curves depending on the media, final water saturation, and fluids. In particular, when the media and fluids are held constant, oil relative permeability can vary an order of magnitude at the same oil saturation, depending on the initial condition and water saturation. We find that within each media, all the curves represent a similar shape, but reach to a different residual saturation. This suggests that residual oil saturation is the key parameter in observed relative permeability differences along different saturation paths. We examine this hypothesis with the most common three-phase relative permeability models, i.e. Saturation Weighted Interpolation, Stone I and II, where we vary residual oil saturation to fit the experimental data. We find that if residual oil saturation is used as a fitting parameter, the models predict experimental data well. Otherwise, without varying residual oil saturation, these relative permeability models perform poorly in predicting experimental data.
Guo, Hu (China University of Petroleum) | Li, Yiqiang (China University of Petroleum) | Gu, Yuanyuan (China University of Petroleum) | Wang, Fuyong (China University of Petroleum) | Yuliang, Zhang (Research Institute of Xinjiang Oilfield Company, CNPC)
ASP flooding is one of the most promising EOR technologies. Lots of laboratory studies and pilot tests have been finished in Daqing oilfield which is the largest oilfield in China. Comparison of two typical strong alkali ASP (WASP) and weak alkali ASP (SASP) pilots are presented with detained information.
ASP flooding could not only remarkably improve displacement efficiency but also improve sweep efficiency due to the low interfacial tension effect and mobility control technique with help of viscosity enhancement and emulsification effects. The incremental recovery of two ASP was near, while in peak oil production period after the injection took effects, WASP had high oil production rate than SASP. The emulsification effects in weak alkali ASP was weaker than strong one. The chromatographic separation was different in two pilot tests, in which weak alkali ASP had alleviated chromatographic separation. The constitution production sequence was both polymer first, then alkali and finally surfactant. The time gap between surfactant and polymer was about 0.0606 PV for strong alkali ASP, while a respective value of 0.1281PV for weak alkali ASP. Scaling was different and thus anti-scale technique adopted in two pilot tests were a little different. The overall input-output ratio for two tests was different and weak alkali ASP performed much better. Comparison was first made between strong alkali and weak alkali based ASP flooding from field tests perspective. Weak alkali based ASP is proven the development trend.