Carbon dioxide (CO2) flooding is a mature technology in oil industry, which finds broad attention in oil production during tertiary oil recovery (EOR). After five decade’s developments, there are many successful reports for CO2 miscible flooding. However, operators recognized that achieving miscible phase is one of big challenge in fields with extremely high minimum miscible pressure (MMP) after considering the safety and economics. Compared with CO2 miscible flooding, immiscible CO2 flooding demonstrates the great potentials under varying reservoir/fluid conditions. A comprehensive and high-quality data set for CO2 immiscible flooding are built by collecting various data from books, DOE reports, AAPG database, oil and gas biennially EOR survey, field reports and SPE publications. Important reservoir/fluid information, operational parameters and project performance evaluations are included, which provides the basis for comprehensive data analysis. Combination plot of boxplot and histogram are generated, where boxplots are used to detect the special cases and to summarize the ranges of each parameter; histograms display the distribution of each parameter and to identify the best suitable ranges for propose guidelines.
Results show that CO2 immiscible flooding could recover additional 4.7 to 12.5% of oil with average injection efficiency of 10.07 Mscf/stb; CO2 immiscible technique can be implemented in light/medium/heavy oil reservoirs with a wide range of net thickness (5.2 - 300 ft); yet in heavy oil specifically reservoir (oil gravity <25 °API) with thin layer (net thickness< 50 ft) is better.
Aldhaheri, Munqith (Missan Oil Company, Dept. of Petroleum Engineering, University of Misan) | Wei, Mingzhen (Missouri University of Science and Technology) | Zhang, Na (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
As lifespan extenders, bulk gels have been widely applied to rejuvenate oil production from uneconomic producers in mature oilfields by improving sweep efficiency of IOR/EOR floodings. This paper presents a comprehensive review for the responses of injection-well gel treatments implemented between 1985 and 2014. The survey includes 61 field projects compiled from SPE papers and U.S. DOE reports. Seven parameters related to the oil production response were evaluated according to the reservoir lithology, formation type, and recovery process using the univariate analysis and stacked histograms. The interquartile range method was used to detect the under-performing and over-performing gel projects. Scatterplots were used to identify effects of the injected gel volume and the treatment timing on the treatment responses.
Results indicated that gel treatments have very wide ranges of responses for injection and production wells and for oil and water rates/profiles. The typical incremental oil production is 116 MSTBO per treatment, 15 STBO per gel barrel, or 10 STBO per polymer pound. We identified that gel treatments perform more efficiently in carbonate than in sandstone reservoirs and in naturally-fractured formations than in other formation types. In addition, the incremental oil production considerably increases with the channeling strength and the injected gel volume for all formation types, not just for the matrix-rock reservoirs. Moreover, gel treatments applied in naturally-fractured formations have lower productivities in sandstones than in carbonates based on the normalized performance parameters.
Declining tends were identified for all parameters of the oil production response with the treatment timing indicators. The sooner the gel treatment is applied; the faster the response and the larger the incremental oil production and its rate. It is recommended to allow longer evaluation times for gel treatments applied in matrix-rock formations or in mature polymer floodings as their response times may extend to several months. Gel treatments would perform more efficiently if they are conducted at water cuts <70%, flood lives <20 years, or recovery factors <35%. For different application environments, the present review provides reservoir engineers with updated ideas about what are the low, typical, and high performances of gel treatments when applied successfully and how other treatment aspects affect the performances.
Alfarge, Dheiaa (Iraqi Ministry of Oil, Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Improved Oil Recovery (IOR) techniques in Unconventional Liquids Rich Reservoirs (ULR) are still a new concept because there is no commercial project for any IOR technique so far. Carbon dioxide (CO2) based EOR technique has been effectively applied to improve oil recovery in the tight formations of conventional reservoirs. Extending this approach to unconventional formations has been extensively investigated over the last decade because CO2 has unique properties which make it the first option of EOR methods to be tried. However, the applications and mechanisms for CO2-EOR in unconventional reservoirs would not necessarily be the same as in conventional reservoirs due to the complex and poor-quality properties of these plays.
Since the first CO2-EOR huff-n-puff project was conducted in conventional reservoirs in Trinidad and Tobago in 1984, more than 130 additional projects have been put in operation around the world, mainly located in USA, Turkey, and Trinidad and Tobago. In this study, we combined Decline Curve Analysis (DCA) for the production data of these projects with numerical simulation methods to produce one typical graph accounts for the main mechanisms controlling CO2-EOR performance in conventional reservoirs. On the other hand, we have couple of CO2-EOR huff-n-puff pilot tests conducted in Bakken formation between 2008 and 2016. Two engineering-reversed approaches have been integrated to produce a unique type curve for the performance of CO2-EOR huff-n-puff process in shale oil reservoirs. Firstly, a numerical simulation study was conducted to upscale the reported experimental-studies outcomes to the field conditions. As a result, different forward diagnostic plots have been generated from different combinations for CO2 physical mechanisms with different shale-reservoirs conditions. Secondly, different backward diagnostic plots have been produced from the history match with CO2 performances in fields’ pilots performed in some portions of Bakken formation located in North Dakota and Montana. Finally, fitting the backward with the forward diagnostic plots was used to produce another unique type curve to represent CO2-EOR performance in shale oil reservoirs. This study found that the delayed response in the incremental oil production resulted from CO2 injection in shale reservoirs is mainly function of CO2 molecular diffusion mechanism. On the other hand, the CO2 diffusion mechanism has approximately no effect on CO2-EOR performance in conventional reservoirs which have a quick response to CO2 injection. This finding is very well consistent with the experimental reports regarding the role of diffusion in conventional cores versus shale cores. In addition, this study found that kinetics of oil recovery process in productive areas and CO2-diffusivity level are the keys to perform successful CO2-EOR project in shale formations. This paper provides a thorough idea about how CO2-EOR performance is different in the field scale of conventional reservoirs versus shale formations.
Alfarge, Dheiaa (Iraqi Ministry of Oil, Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
In shale oil reservoirs, Improved Oil Recovery (IOR) methods are relatively considered as new concepts compared with in conventional oil reservoirs. Different IOR techniques have been investigated by using lab experiments, numerical simulation studies, and limited pilot tests. Unconventional IOR methods include injecting CO2, surfactant, natural gas, and water. However, CO2 injection is the most investigated option due to different reasons. CO2 has lower miscibility pressure with shale oils, and has special properties in its supercritical conditions, and CO2 injection also solves greenhouse problems. In this paper, numerical simulation methods of compositional models were incorporated with LS-LR-DK (logarithmically spaced, locally refined, and dual permeability) reservoir models and Local Grids Refinement (LGR) of hydraulic fractures conditions to investigate the feasibility of CO2 injection in shale oil reservoirs. Different mechanisms for CO2 interactions with organic surface, shale brine, and shale oil were implemented in different scenarios of numerical models. Molecular diffusion mechanisms, adsorption effects, and aqueous solubility effects were simulated in this study. In addition, linear elastic models and stress-dependent correlations were used to consider geomechanics coupling effects on production and injection processes of CO2-EOR in shale oil reservoirs. Some of the results for this simulation study were validated by matching the performance of some CO2 fields’ pilots performed in Bakken formation, in North Dakota and Montana portions.
This study extremely found that some of the CO2-EOR pilot tests have a match with the typical simulated diagnostic plots which have CO2 molecular-diffusion rate that is significantly low. Furthermore, this research indicated that CO2 molecular diffusion mechanism has a clearly positive effect on CO2-EOR in huff-n-puff protocol; however, this mechanism has a relatively negative effect on continuous flooding mode of CO2-EOR. Both of dissolution and adsorption mechanisms have a negative effect on CO2 performance in terms of enhancing oil recovery in unconventional formations. Geomechanics coupling has a clear effect on CO2-EOR performance, and different geomechanics models have a different validity in these shale plays. Stress dependent correlations give the best match with CO2-EOR pilots in Bakken formation while linear elastic models would give the best match in Eagle Ford formation. This study explains the effects of different nano and macro mechanisms on the performance of CO2-EOR in unconventional reservoirs since these plays are much complex and very different from conventional formations. Also, general guidelines have been provided in this study to enhance success of CO2-EOR in these types of reservoirs.
Lu, Yao (China University of Petroleum, Beiijing) | Li, Zhe (China University of Petroleum, Beiijing) | Wu, Hairong (China University of Petroleum, Beiijing) | Jiang, Jiatong (China University of Petroleum, Beiijing) | Jiang, Jianfang (China University of Petroleum, Beiijing) | Hou, Jirui (China University of Petroleum, Beiijing) | Kang, Wanli (China University of Petroleum, East China) | Yang, Hongbin (China University of Petroleum, East China) | Zhang, Xiangfeng (China University of Petroleum, East China) | Bai, Baojun (China University of Petroleum, Beijing at Karamay, Missouri University of Science and Technology)
It has been proven by field tests that crude oil recovery could be enhanced with the generation of stable emulsions. Amphiphilic polymers display better capability in emulsifying crude oil as compared with that of traditional polymers attributing to the co-existence of hydrophilic and hydrophobic groups in molecular chains. To investigate the generation of emulsified oil droplets with the hydrophobically modified polyacrylamide (HMPAM) in reservoirs, porous mesh shearing method to generate emulsions was first conducted. The stabilization mechanism was then elucidated by comparing properties of emulsions which are stabilized by HMPAM with different degree of β-cyclodextrin (β-CD) inclusion. The flow behavior of various HMPAM emulsions was further evaluated by rheological method and comparative seepage experiments. The results show that the snapping action of residual oil and the shearing action of HMPAM solution in porous media are the main reasons of the generation of emulsions, the emulsifying property of which is mainly affected by the concentration of HMPAM, injection rate, migration distance as well as the average diameter of pore throats. β-CD could mask hydrophobic groups on HMPAM molecules because of the host-guest interaction, resulting in a transition of corresponding polymer emulsion from stable state to unstable one. Over 80% reduction in stability index is observed after inclusion for the emulsion with polymer concentration above the critical aggregation concentration, indicating that the presence of hydrophobic groups is the most important source of emulsifying and stabilizing capability of HMPAM. Furthermore, the viscoelasticity of the emulsion system is enhanced by the synergistic effect of supramolecular networks and emulsified oil droplet. During its transport through porous media, the polymer emulsion shows high flow resistance and its injection pressure exhibits an obviously creeping fluctuation increasing phenomenon as compared to surfactant emulsion and sheared polymer solution.
Imqam, Abdulmhsin (Missouri University of Science and Technology) | Wang, Ze (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Delshad, Mojdeh (The University of Texas at Austin)
Preformed particle gels (PPG) have been successfully applied as a plugging agent to solve the conformance problem in fractured reservoirs. They are injected to plug fractures and then divert displacing fluid into poorly swept zones and areas. However, PPG propagation and plugging mechanisms through open fractures have not been studied thoroughly. This paper investigated the influence of some factors (particle size, brine concentration, heterogeneity, injection flow rate, and brine salinity) on gel injectivity and plugging performance for water flow through opening fractures. Five-foot tubes were used to mimic opening fractures. Three models were designed to gain understanding on how fracture geometry and PPG properties affect gel injection and plugging efficiency, including (1) single fracture with uniform fracture width, (2) single fracture with different widths, and (3) two parallel fractures with different width ratios between each other. Results from single uniform fracture experiments showed that PPG injection pressure was more sensitive to gel strength than gel particle size. When large PPG size and high gel strength were used, high injection pressure and large injection pore volume were required for PPG and brine to reach fracture outlets. Results from single heterogeneous fracture model experiments showed PPG injection pressure increased as the fracture heterogeneity in sections increased. Particle gel accumulated at the choke point within each fracture and caused injection pressure to increase accordingly. Furthermore, results showed that having a lower salinity within a fracture, which was less than the brine salinity that was used to prepare PPG, would improve the PPG plugging efficiency for water flow. Parallel fracture models results showed that when weak PPG was used, a large volume of PPG flowed into a large fracture width and a small portion of the gel particle volume flowed into small fracture width. However, with increased gel strength and fracture width ratio, PPG only flowed through larger fracture widths. This paper demonstrates important impact elements of gel propagation and water flow for different opening fracture situations.
Zhang, Yandong (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Yang, Hongbin (China University of Petroleum) | Kang, Wanli (China University of Petroleum)
Enhanced oil recovery (EOR) processes are regarded as important methods to recover remaining oil after primary and secondary recovery. It is important to select the most appropriate EOR process among the possible techniques for a candidate reservoir. Therefore, EOR screening criteria have been constructed using available EOR data sets and serve as the first step to compare the suitability of each EOR method for a particular reservoir. Most screening criteria for polymer flooding are based on data sets from EOR surveys published biannually by the Oil & Gas Journal. These surveys missed significant polymer flooding parameters such as formation water salinity and hardness, polymer types and molecular weight, polymer concentration, reservoir heterogeneity, and so on. All of these topics are covered in this paper with data from relevant literature and records provided by oil companies in China.
Polymer flooding has been widely applied in China for over 20 years and a large number of pilot and field projects have been conducted. These projects include important information to quantify the development of polymer flooding as an EOR method. Nevertheless, most of them have been published in Chinese, and are not accessible to the global research community due to the language barrier. This paper represents an effort to collect all relevant information of polymer flooding from available Chinese publications and reports from all of the major oil companies in China. The primary objectives of this survey is to reveal EOR advances, to trace the development of the polymer flooding EOR methodology in China, and to benefit EOR worldwide.
This project collected information on 55 polymer flooding projects after reviewing nearly 200 publications in Chinese, including 31 pilot projects and 24 field projects from 1991 to 2014. A data set was constructed by collecting all relevant information for polymer flooding. Statistical analyses and graphical methods were used to analyze the whole data set. Box plots combined with violin plots were used to show the distribution and the range of each parameter. By defining and calculating lower and upper limits in box plots, special projects were identified and explained. Scatter plots, which show multiple parameters in one plot, were used to identify significant relationships among different parameters, especially for dependent parameters. This method overcomes some disadvantages of the range method, which is traditionally used for EOR screening. For example, using polymers with high concentration in low salinity reservoirs can lead to higher incremental oil recovery than in high salinity ones, and lower permeability usually correlates with the use of polymers with lower molecular weight. However, the traditional range method cannot show this relationship. Finally, comprehensive screening criteria for polymer flooding were updated based on information revealed in the field application projects.
Aldhaheri, Munqith N. (Missan Oil Company, Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Polymer gels are increasingly applied to improve sweep efficiency of different IOR/EOR recovery processes. Three in-situ polymer gel systems including bulk gels, colloidal dispersion gels, and weak gels are often used to mitigate water production caused by reservoir heterogeneity and unfavorable mobility ratio of oil and injected fluids. Selecting the most appropriate gel system is a key component for a successful conformance improvement treatment. Screening criteria in terms of reservoir and fluid characteristics have been widely used to identify potential technologies for a specific reservoir. Despite the large number of polymer gel projects, only five, limited-parameters, single-agent criteria or surveys have been sporadically accomplished that suffer from many deficiencies and drawbacks.
This paper presents the first complete applicability guidelines for gel technologies based on their field implementations in injection wells from 1978 to 2015. The data set includes 111 cases histories compiled mainly from SPE papers and U.S. Department of Energy reports. We extracted missing data from some public EOR databases and detected potential outliers by two approaches to ensure data quality. Finally, for each parameter, we evaluated project and treatment frequency distributions and applicability ranges based on successful projects. Extensive comparisons of the developed applicability criteria with the previous surveillance studies are provided and differences are discussed in details as well.
In addition to the parameters that are considered for other EOR technologies, we identified that the applicability evaluations of polymer gels should incorporate the parameters that depict roots and characteristics of conformance issues. The present applicability criteria comprise 16 quantitative parameters including permeability variation, mobility ratio, and three production-related aspects. Application guidelines were established for organically crosslinked bulk gels for the first time, and many experts' opinions in the previous criteria were replaced by detailed property evaluations. In addition, we identified that the applicability criteria of some parameters are considerably influenced by lithology and formation types, and thus, their data were analyzed according to these characteristics. Besides their comprehensiveness of all necessary screening parameters, the novelty of the new criteria lies in their ability to self-check the established validity limits for the screening parameters which resulted from the inclusion and simultaneous evaluation of the project and treatment frequencies.