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.
Cold heavy oil production with sand (CHOPS) involves the deliberate initiation of sand influx during the completion procedure, maintenance of sand influx during the productive life of the well, and implementation of methods to separate the sand from the oil for disposal. No sand exclusion devices (screens, liners, gravel packs, etc.) are used. The sand is produced along with oil, water, and gas and separated from the oil before upgrading to a synthetic crude. To date, deliberate massive sand influx has been used only in unconsolidated sandstone (UCSS) reservoirs (φ 30%) containing viscous oil (μ 500 cp). It has been used almost exclusively in the Canadian heavy-oil belt and in shallow ( 800 m), low-production-rate wells (up to 100 to 125 m3/d).
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.
The claim that the world is irresponsible in rapidly consuming irreplaceable resources ignores technical progress, market pressures, and the historical record. For example, the "Club of Rome," with the use of exponential growth assumptions and extrapolations under static technology, predicted serious commodity shortages before 2000, including massive oil shortages and famine. First, the new production technologies are proof that science and knowledge continue to advance and that further advances are anticipated. Second, oil prices will not skyrocket because technologies such as manufacturing synthetic oil from coal are waiting in the wings. Third, the new technologies have been forced to become efficient and profitable, even with unfavorable refining penalties. Fourth, exploration costs for new conventional oil production capacity will continue to rise in all mature basins, whereas technologies such as CHOPS can lower production costs in such basins. Fifth, technological feedback from heavy-oil production is improving conventional oil recovery. Finally, the heavy-oil resource in UCSS is vast. Although it is obvious that the amount of conventional (light) oil is limited, the impact of this limitation, while relevant in the short term (2000 to 2030), is likely to be inconsequential to the energy industry in the long term (50 to 200 years). The first discoveries in the Canadian heavy-oil belt were made in the Lloydminster area in the late 1920s. Typically, 10- to 12-mm diameter perforations were used, and pump jacks were limited by slow rod-fall velocity in the viscous oil to a maximum of 8 to 10 m3/d of production, usually less. Operators had to cope with small amounts of sand, approximately 1% in more viscous oils. Small local operators learned empirically that wells that continued to produce sand tended to be better producers, and efforts to exclude sand with screens usually led to total loss of production. Operators spread the waste sand on local gravel roads and, in some areas, the roadbeds are now up to 1.5 m higher because of repeated sand spreading. The sharp oil price increases in the 1970s and 1980s led to great interest in heavy-oil-belt resources (approximately 10 109m3). Many international companies arrived and introduced the latest screen and gravel-pack technology but, in all cases, greatly impaired productivity or total failure to bring the well on production was the result. To this day, there are hundreds of inactive wells with expensive screens and gravel packs. The advent of progressing cavity (PC) pumps in the 1980s changed the nonthermal heavy-oil industry in Canada. The first PC pumps had low lifespans and were not particularly cost-effective, but better quality control and continued advances led to longer life and fewer problems. The rate limits of beam pumps were no longer a barrier and, between 1990 and 1995, operators changed their view of well management.
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).
Al-Bayati, Duraid (Curtin University) | Saeedi, Ali (Kirkuk University) | Ghasemi, Mohsen (Curtin University) | Arjomand, Eghan (Curtin University) | Myers, Mathew (Curtin University) | White, Cameron (CSIRO-Energy) | Xie, Quan (CSIRO-Energy)
Carbon dioxide (CO2) injection has been identified as an important means to achieve hydrocarbon reservoir potential whilst mitigating the greenhouse gas effect. CO2 injection into depleted oil reservoirs is very often accompanied by chemical interactions between the formation rock and in situ formed solute. Sandstone formations were expected to contain less reactive minerals in their composition, compared with carbonate counterparts. However, the evolution of petrophysical parameters may change due to different clay content in different sandstone rocks. In this manuscript, we evaluate possible petrophysical parameter evolution in layered sandstone core sample during miscible CO2 water alternating gas (WAG) injection. The stratified core sample is composed of two axially split half sandstone plugs each with different permeability. Grey Berea, Bandera Brown, and Kirby sandstone were used to represent low, moderate and high clay content, respectively. Core flooding experiments were conducted using CO2, brine (7 wt % NaCl + 5 wt % KCl + 5 wt % CaCl2.2H2O) and
The results showed a reasonable increase in the post-flood porosity about 1.0% as a maximum. The results also revealed that the changes in porosity are correlated reasonably with the clay minerals amount in the sample (i.e. higher clay mineral amount leads to higher evolution). The X-ray CT images and NMR results confirmed changes in pore spaces and pore size distribution across the core sample. These changes possibly attributed to clay minerals migration which released by mineral dissolution and subsequent pore throat plugging. NMR results also revealed that the larger the pore size, accompanied by high clay mineral amount, the higher the evolution. This may be attributed to the higher contact surfaces at these pores with the injected CO2 (in-situ formed carbonic brine).
Our results provide insight into how clay content may affect CO2/sandstone reaction in the presence of permeability/mineralogy heterogeneity. In addition, it highlights the control of clay content on rock petrophysical parameter evolution, thus its significance in modelling CO2 injection in sandstone reservoirs.
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.
Alkinani, Husam H. (Missouri University of Science and Technology) | Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Flori, Ralph E. (Missouri University of Science and Technology) | Alsaba, Mortadha T. (Australian College of Kuwait) | Amer, Ahmed S. (Newpark Technology Center/ Newpark Drilling Fluids)
Oil/gas exploration, drilling, production, and reservoir management are challenging these days since most oil and gas conventional sources are already discovered and have been producing for many years. That is why petroleum engineers are trying to use advanced tools such as artificial neural networks (ANNs) to help to make the decision to reduce nonproductive time and cost. A good number of papers about the applications of ANNs in the petroleum literature were reviewed and summarized in tables. The applications were classified into four groups; applications of ANNs in explorations, drilling, production, and reservoir engineering. A good number of applications in the literature of petroleum engineering were tabulated. Also, a formalized methodology to apply the ANNs for any petroleum application was presented and accomplished by a flowchart that can serve as a practical reference to apply the ANNs for any petroleum application. The method was broken down into steps that can be followed easily. The availability of huge data sets in the petroleum industry gives the opportunity to use these data to make better decisions and predict future outcomes. This paper will provide a review of applications of ANNs in petroleum engineering as well as a clear methodology on how to apply the ANNs for any petroleum application.
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.
Oily sludge is one of the main wastes produced during oilfield development. The composition of oily sludge is complex, resulting in difficult separation and high processing cost. The existing technologies such as landfill, microbiological deterioration, heat treatment and solvent extraction are difficult to meet the needs of oily sludge treatment. It is necessary to develop a highly efficient and cheap reutilization technology for oily sludge. For this reason, we have proposed to recycle the oily sludge which can be utilized to profile control in water injection and thermal recovery wells.
In the process of research, we have developed five aspects of work: First, three-phase separation of oily sludge was carried out by distillation, and water quality, oil-phase composition and solid particle size were analyzed. The compatibility of oily sludge and oil reservoir was investigated. Second, the mechanism and influence factors of the oily sludge for profile control were studied by long core model test and microscope observation. Third, suspension analysis and mobility analysis were developed on oily sludge, and experimental results were used to research oily sludge profile control agent. Fourth, numerical simulation was used to optimize the engineering design of Oily Sludge Profile Control (OSPC). Fifth, ground process flow of oily sludge for profile control was designed.
The following conclusion can be drawn from the study: OSPC is a Reutilization Technology for oily sludge, which could seal up oily sludge in-situ in oil reservoir and be favorable for increasing production of oil wells through profile control. Through the rheology and plugging test, it was clear that OSPC could greatly reduce the pollution risk of oily sludge and the ground treatment cost, and solid phase and oil phase of mud were retained in the formation. It could plug high permeability channels and high permeability area (the plugging rate was more than 90%) to adjust water/steam injection profile of water/thermal recovery wells. Profile control agent, engineering design method and ground process flow for oily sludge were developed. The technology applied 72 wells in the oilfield, 184 thousand tons of oily sludge were used in total, production of crude oil was increased by 84 thousand barrels, and a lot of sludge treatment costs could be saved.