Dong, Xiaohu (China University of Petroleum, Beijing) | Liu, Huiqing (China University of Petroleum, Beijing) | Lu, Ning (China University of Petroleum, Beijing) | Zheng, Aiping (Xinjiang Oilfield Company, CNPC) | Wu, Keliu (China University of Petroleum, Beijing) | Xiao, Qianhua (Chongqing University of Science & Technology) | Wang, Kung (University of Calgary) | Chen, Zhangxin (University of Calgary)
Considering the non-uniform steam conformance of conventional horizontal well, dual-pipe steam injection technique has currently demonstrated technical potential for improving heavy oil recovery. It can delay the occurrence of steam fingering and homogenize the steam injection profile along horizontal wellbore. But in some field tests, it is observed that the results were far greater than such an approach would have justified. In addition, the actual physics are still unclear, and not demonstrated. In this paper, first, we built a cylindrical wellbore physical model to experimentally study steam injection profiles of a single pipe horizontal well and a concentric dual-pipe horizontal well. Thus, the heat and mass transfer behavior of steam along horizontal well with a single-pipe well configuration and a dual-pipe well configuration was addressed. Subsequently, considering the effect of pressure drops and heat loss, a semi-analytical model for the gas-liquid two-phase flow in horizontal wellbore was developed to numerically match the experimental observation. Next, a sensitivity analysis on the physical parameters and operation properties of a steam injection process was conducted. The effect of the injection fluid type was also investigated.
Experimental results indicated that under the same steam injection condition, an application of the dual-pipe well configuration can significantly enhance the oil drainage volume by about 35% than the single-pipe well configuration. During the experiments, both a temperature distribution and liquid production along the horizontal wellbore were obtained. A bimodal temperature distribution can be observed for the dual-pipe well configuration. From this proposed model, an excellent agreement can be found between the simulation results and the experimental data. Because of the effect of variable-mass flowing behavior and pressure drops, the wellbore segment closed to the steam outflow point can have a higher heating radius than that far from the steam outflow point. From the results of sensitivity analysis, permeability heterogeneity and steam injection parameters have a tremendous impact on the steam injection profile along wellbore. Compared with a pure steam injection process, the co-injection of steam and NCG (non-condensable gas) can improve the effective heating wellbore length by over 25%. Furthermore, this model is also applied to predict the steam conformance of an actual horizontal well in Liaohe oilfield. This paper presents some information regarding the heat and mass transfer of a dual-pipe horizontal well, as well as imparts some of the lessons learned from its field operation. It plays an important role for the performance evaluation and remaining reserve prediction in a dual-pipe thermal recovery project.
Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.
This page provides a brief review of illustrative field applications of polymer waterflooding as reported in the literature. In 1983, Manning et al. published a comprehensive and classic summary of the field results and performance of more than 250 polymer waterflooding projects and provided information relating to the early field applications of polymer waterflooding. Figure 1 shows the incremental oil production response for the North Burbank polymer flood. A polymer waterflooding project that involved a large full-field flooding project at the North Oregon Basin field in Wyoming's mature Big Horn Basin oil-producing area was reported in 1986 to be producing 2,550 BOPD of incremental oil production. It was reported that this polymer flooding project would recover ultimately more than 10 million bbl of incremental reserves from the mature North Oregon Basin field. The field project involved the flooding of both a fractured carbonate formation and a fractured sandstone formation with a polymer flood using partially hydrolyzed polyacrylamide(HPAM).
Li, Yingcheng (Sinopec Shanghai Research Institute of Petrochemical Technology) | Kong, Bailing (Sinopec Henan Oil Field Company) | Zhang, Weidong (Sinopec Shanghai Research Institute of Petrochemical Technology) | Bao, Xinning (Sinopec Shanghai Research Institute of Petrochemical Technology) | Jin, Jun (Sinopec Shanghai Research Institute of Petrochemical Technology) | Wu, Xinyue (Sinopec Shanghai Research Institute of Petrochemical Technology) | Liu, Yanhua (Sinopec Henan Oil Field Company) | Wang, Yanxia (Sinopec Henan Oil Field Company) | He, Xiujuan (Sinopec Shanghai Research Institute of Petrochemical Technology) | Zhang, Hui (Sinopec Shanghai Research Institute of Petrochemical Technology) | Shen, Zhiqin (Sinopec Shanghai Research Institute of Petrochemical Technology) | Sha, Ou (Sinopec Shanghai Research Institute of Petrochemical Technology) | Yang, Weimin (Sinopec Shanghai Research Institute of Petrochemical Technology)
Cationic surfactant is never used in Enhanced Oil Recovery (EOR) for negative charged sandstone reservoirs because of high adsorption. Since January 2012, the first field scale application of alkaline surfactant polymer (ASP) flood in the world with thermal stable, highly efficient mixtures of anionic-cationic surfactants (S) for super low acid oils, was carried out in Sinopec for a high water cut mature sandstone reservoir with approximately 8,000 mg/L total dissolved solids (TDS), temperature of 81 C, to demonstrate the potential of this novel surfactants to recover residual oil from as high as 53.3% recovery percent of reserves. The maximal water cut decreased from 97.9% to 90.2%, along with peak daily oil production increased from 23.0 t to 106.1 t. The cumulative incremental oil by ASP flood at the end of December 2018 is about 276.1 kt and the oil recovery was increased by 10.65% OOIP. The estimated ultimate oil recovery can be increased by 14.2% OOIP and yield up to 67.5% OOIP.
Guo, Hu (China University of Petroleum, Beijing) | Li, Yiqiang (China University of Petroleum, Beijing) | Kong, Debin (China University of Petroleum, Beijing) | Ma, Ruicheng (China University of Petroleum, Beijing) | Li, Binhui (China University of Petroleum, Beijing) | Wang, Fuyong (China University of Petroleum, Beijing)
Although the alkali/surfactant/polymer (ASP) flooding technique used for enhanced oil recovery (EOR) was put forward many years ago, it was not until 2014 that it was first put into practice in industrial applications with hundreds of injectors and producers in the Daqing Oil Field in China. In this study, 30 ASP-flooding field tests in China were reviewed to promote the better use of this promising technology. Up to the present, ASP flooding in the Daqing Oil Field deserves the most attention.
Alkali type does affect the ASP-flooding effect. Strong alkali [using sodium hydroxide (NaOH)] ASP flooding (SASP) was given more emphasis than weak alkali [using sodium carbonate (Na2CO3)] ASP flooding (WASP) for a long time in the Daqing Oil Field because of the lower interfacial tension (IFT) of the surfactant and the higher recovery associated with NaOH than with Na2CO3. Other ASP-flooding field tests completed in China all used Na2CO3. With progress in surfactant production, a recent large-scale WASP field test in the Daqing Oil Field produced an incremental oil recovery nearly 30% higher than most previous SASP recoveries and close to the value of the most-successful SASP test. However, the most-successful SASP test was partly attributed to the weak alkali factor. Recent studies have shown that the WASP incremental oil recovery factor could be as good as that of SASP but with much-better economic benefits.
Screening of surfactant by IFT test is very important in the ASP-flooding practice in China. Whether dynamic or equilibrium IFT should be selected as criteria in surfactant screening is still in dispute. Many believe the equilibrium IFT is more important than the dynamic IFT in terms of the displacement efficiency; thus, it is better to choose a lower dynamic IFT when the equilibrium IFT meets the 10–3 order-of-magnitude requirement. However, it is impossible for many surfactants to form ultralow equilibrium IFT. Because of the low acid value of the Daqing crude oil, the asphaltene and resin components play a very important role in reducing the oil/water IFT and asphaltene is believed to be more influential, although more work is required to resolve this controversial issue.
Whether polymer viscoelasticity can reduce the residual oil saturation is still a matter of debate. Advances in surfactant production and in the overcoming of scaling and produced-fluid-handling challenges form the foundation of the industrial application of ASP flooding. Further work is advised on the emulsification effect of ASP flooding. According to one field test, the EOR routine should be selected depending on consideration of the residual oil type to decide whether to increase the sweep volume and/or displacement efficiency. The micellar flooding failure in one ASP field test in China has led all subsequent field tests in China to choose the “low concentration, large slug” technical route instead of the “high concentration, small slug” one. ASP flooding can increase oil recovery by 30% at a cost of less than USD 30/bbl; thus, this technique can be used in response to low-oil-price challenges.
Lu, Chuan (Research Institute of China National Offshore Oil Corporation) | Liu, Huiqing (China University of Petroleum, Beijing) | Zhao, Wei (China University of Petroleum, Beijing) | Lu, Keqin (China National Petroleum Corporation) | Liu, Yongge (China University of Petroleum, East China) | Tian, Ji (Research Institute of China National Offshore Oil Corporation) | Tan, Xianhong (Research Institute of China National Offshore Oil Corporation)
In this study, the effects of viscosity-reducer (VR) concentration, salinity, water/oil ratio (WOR), and temperature on the performance of emulsions are examined on the basis of the selected VR. Different VR-injection scenarios, including single-VR injection and coinjection of steam and VR, are conducted after steamflooding by use of single-sandpack models. The results show that high VR concentration, high WOR, and low salinity are beneficial to form stable oil/water emulsions. The oil recoveries of steamflooding for bitumen and heavy oil are approximately 31 and 52%, respectively. The subsequent VR flooding gives an incremental oil recovery of 5.2 and 6.4% for bitumen and heavy oil, respectively. Flooding by steam/VR induces an additional oil recovery of 8.4–11.0% for bitumen and 12.1% for heavy oil. High-temperature steam favors the peeling off of oil and improving its fluidity, as well as the in-situ emulsions. VR solution is beneficial for the oil dispersion and further viscosity reduction. The coinjection of high-temperature steam and VR is much more effective for additional oil production in viscous-oil reservoirs.
With the increasing global demand for energy, great attention has been focused on utilizing heavy oil and bitumen, which cannot be easily recovered. This has been achieved by reservoir heating using conventional methods such as steam. However, these approaches are often accompanied by high energy consumption, large amounts of wastewater generation, and undesirable environmental damage. Recently, nanoparticles have become an attractive agent for enhancing oil recovery (EOR) in the laboratory scale. In addition, nanotechnology was chosen as an alternative method to unlock the remaining oil resources during the last decade. Consequently, this research provides one of the promising techniques for in-situ heavy oil recovery using metal-based nanoparticles to maintain in-situ heat generated by steam. Several core flood experiments were conducted to compare the recovery of Kuwaiti heavy oil using; hot water, superheated steam (SH), nanofluids, and combination of nanofluids and SH team.
Initially, the individual hydrophilic nanoparticles (HFNPs) including; zirconium dioxide (ZrO2), titanium dioxide (TiO2), zinc oxide (ZnO), and iron oxide (alpha) (Fe2O3-α), of average particle size (APS) of 20–50 nm and different thermal conductivities, were dissolved in formation water to create stable nanofluids. The results of the nanofluids coreflooding showed that ZrO2 provides higher oil recovery than TiO2, Fe2O3-α, or ZnO. However, the combination of ZrO2 (low thermal conductivity) at a concentration of 0.05 wt% with SH at 1 PV exhibits highest oil recovery near 46.9%, followed by combination of ZnO (high thermal conductivity) at same concentration with SH which had a recovery of 42.7%, then followed by SH steam of 35% recovery. This indicates the ability of HFNP with low APS and low thermal conductivity of providing promising EOR results when combined with low steam consumption and low produced water.
Fula field at Block 6, Sudan contains crude of 16.8 to 19 °API with in-situ viscosity of 497 cp in Bentiu formation. It was on production in March, 2004 and has produced 14% of original oil in place. Massive and unconsolidated sandstones inter-bedded with thin (3 to 13 ft) and discontinuous shales possess high horizontal and vertical permeabilities (2 to 9.53 Darcies). Lateral dimensions of shale bodies range from 1,000 to 2,000 ft. To extend oil production life with water-free, initial development strategy was to perforate the upper and more permeable zones (Perforations are 30% of entire zones) to obtain profitable productivity. After fieldwide water breakthrough, based on the studies of bypassed oil distribution, the following innovative deeper re-completions have been applied in high-water-cut wells (water cut more than 80%) to exploit the bypassed oil zones and new pay zones that have been missed below the existing productive zones.
(1). squeeze cement into the existing high-water-cut zones, located at the upper portion of entire pay zones. Those long wormholes communicating with aquifer caused by deep sanding should be cemented.
(2). perforate partially the lower portion of pay zones with optimal shot density. 30 to 40% of entire pay zones and shot density of 5 shots per foot are recommended. Perforation tunnel optimization can be run for concrete well conditions.
(3). Progressing Cavity Pumps operate at low frequencies less than 30 Hz to regulate proper pressure drawdown less than observed critical value of sanding from field tests and water coning.
Field production data indicate that this workover campaign has achieved more than 2-fold oil gain and reducing water cut by 30 to 50% compared to previous water cuts of over 80%, also, water cut plus dynamic fluid level remain relatively stable over 6 months.
Fula field is located at the east part of Fula sub-basin, South Kordofan State, southeast of Sudan. It was discovered in May, 2001by the exploration well Fula North-1, which intersected both 34 ft of oil-bearing Aradeiba reservoir and 174 ft of oil-bearing Bentiu reservoir, with oil-bearing area of approximate 1,977 acres. Bentiu formation, of Cretaceous age, is the main producing horizon of the field. Structurally, as shown in Fig.1, is characterized by an elongated horst block controlled by two main normal faults. It includes a sequence of relatively massive sandstones interbedded with thin shales in 3 to 13 ft, deposited in braided river environment, with active bottom aquifer support (Fig. 2).
Foam has been used to improve the efficiency of steam injection since the late 1970s and the process has been applied successfully in several fields in particular in California but interest sagged at the end of the 1990s due to low oil prices and little activity took place for several years. The topic has however become more popular in the recent years due to higher oil prices. Foam is generated by the introduction of surfactant along with the steam into the reservoir and reduces its mobility, thus improving the sweep efficiency and reducing heat losses. There has been no review of the process since the classical work by Hirasaki (Hirasaki 1989) and this paper proposes to remedy the situation and present a state of the art of the process. The paper will revisit the field tests from the 1980 and then focus on the recent developments in the laboratory where researchers are attempting to develop new workflows and improved surfactant formulations for better performances; in the field with some recent pilot tests; and in terms of reservoir simulations. This paper will allow engineers to get a complete and up to date understanding of the characteristics and limitations of the process and some guidance as to whether foam could help improve the performances of their steam injection projects.
Temizel, Cenk (Aera Energy) | Zhang, Ming (University of Akron) | Balaji, Karthik (University of Southern California) | Ranjith, Rahul (University of Southern California) | Zheng, Wei (University of Tulsa)
Asphaltene precipitation is caused by numerous factors such as changes in pressure, temperature, and composition. Drilling, completion, acid stimulation, and hydraulic fracturing activities can also induce precipitation in the near-wellbore region. Heavier crudes that contain a larger amount of asphaltene have very few asphaltene precipitation problems because they can dissolve more asphaltene. Thus, it is crucial to understand the significance of each uncertainty and control variables not only theoretically, but also with application to real-life examples such as with this model that uses a 32-degree API South American oil to demonstrate the importance of each variable to shed light in order to efficiently manage such reservoirs.
A commercial optimization and uncertainty tool is coupled with a full-physics commercial simulator that models the phenomenon in order to investigate the significance of major parameters on performance of wells in temperature-dependent asphaltene precipitation and irreversible flocculation. Temperature-dependent asphaltene precipitation and irreversible flocculation are modelled where no precipitation occurs at the original reservoir temperature, and flocculated asphaltene is allowed to deposit via surface adsorption and pore throat plugging. The exponent in the power law relating porosity reduction to the permeability resistance factor is modified to change the effect of asphaltene deposition on permeability reduction.
Lower temperatures are specified around the wellbore causing asphaltene precipitation. Sensitivity and optimization have been done on major reservoir parameters, such as, fluid and rock properties and well operational parameters, and significance of each has been illustrated in tornado diagrams. It is observed that a robust approach on handling of uncertainties in reservoir are as important as management of well operational parameters in the scope of reservoir management.
This study provides an in-depth optimization and uncertainty analysis to outline the significance of each major parameter involved in production performance and ultimately the recovery efficiency in reservoirs with temperature-dependent asphaltene precipitation and irreversible flocculation.