We present the first comprehensive experimental evaluation of CO2 EOR in organic rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic rich shale reservoirs, whereas tests in re-saturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slim-tube MMP on recovery. 18 core-flooding experiments were conducted in sidewall cores from different shale plays.
The cores re-saturated with crude oil, were first cleaned by Dean-Stark extraction, and submitted to porosity and compressibility determination. The re-saturation, confirmed by CT-scanning, was attained by aging the core plugs at high pressure for two to four months. In all experiments, glass beads surrounding core samples were used to simulate the proppant and physically recreate in the laboratory a hydraulic fracture connected to the shale matrix. The slim-tube MMP was measured with CO2, and core-flooding experiments were performed below, close to, and above the MMP. The displacement equipment was coupled to a medical CT-scanner that enabled us to track the changes in composition and saturation taking place within the shale cores during the experiments. Continuous CO2 injection and huff-and-puff were evaluated using soak time from zero to 22 hours. Fixed reservoir temperature was used in all the experiments.
Recovery factors ranged from 1.7 to 40%. The wide variation was the result of different experimental conditions for pressure and soak time. Both operational parameters were found to significantly affect the recovery. Increasing soak time at constant pressure consistently resulted in significant increase in recovery. The increase varied from 78 to 464% for different pressures and oil composition. Similarly, increasing operating pressure at constant soak time resulted in significant increase in recovery factor from 44 to 338% depending on soak time and oil composition. Unlike the typical response during CO2 EOR in conventional rocks, in organic rich shale, further pressure increases beyond the slim-tube MMP continued to increase the recovery factor significantly. In all runs, almost all oil recovery occurred within three days from the start of the experiment, and in all huff-and-puff tests the highest rate of recovery was observed in the first cycle, implying oil recovery with CO2 is a fast process, in comparison to oil re-saturation of the samples which occurs at a significantly slower rate.
This investigation demonstrates CO2 EOR is a technically feasible method to extract significant amounts of crude oil from organic rich shale reservoirs and it provides operational understanding of how to manage pressure and soak time to maximize recovery. The recovery factors obtained in this investigation, in the context of the vast reserves of crude oil contained in organic rich shale, can sustain a second shale revolution and further capitalize oilfield infrastructure.
This paper presents numerical modeling of low tension surfactant gas based EOR method. In this process, slugs of various surfactant solutions and gas are alternated injected to mobilize remained oil left from water flood. The objective of this paper is to model the mechanisms behind the process by history matching the experimental data and simulation of a field-scale reservoir pilot. A four-phase chemical flooding reservoir simulator (UTCHEM) was used to history match a published core flood experiment and simulate a pilot-scale case. The results from the history match reveale that interfacial tension (IFT) reduction between oil and water by surfactant, displacement of oil by gas, and the mobility control of gas are the main mechanims lead to a substantioal increase in oil recovery. Based on these key findings, modeling of the low-tension surfactant-gas flood shows that such a process is very positive for low permeability reservoirs with a 90% oil recovery of the initial oil saturation (Sio=0.56) in a coreflood experiment and a range of recovery factors between 50% to 70% of the water flood in large scale cases.
Aamodt, G. (ConocoPhillips Skandinavia AS) | Abbas, S. (ConocoPhillips Co) | Arghir, D. V. (ConocoPhillips Skandinavia AS) | Frazer, L. C. (ConocoPhillips Co) | Mueller, D. T. (ConocoPhillips Co) | Pettersen, P. (ConocoPhillips Skandinavia AS) | Prosvirnov, M. (ConocoPhillips Skandinavia AS) | Smith, D. D. (ConocoPhillips Co) | Jespersen, T. (Halliburton Co.) | Mebratu, A. A. (Halliburton Co.)
This paper discusses a field case review of the processes used to identify, characterize, design and execute a solution for a waterflood conformance problem in the Ekofisk Field that developed in late 2012. The Ekofisk Field is a highly-fractured Maastrichtian chalk reservoir located in the Norwegian sector of the North Sea. Large scale water injection in the field began in 1987 and overall the field has responded well to waterflood operations. However, fault reactivation coupled with extensive natural fractures and rock dissolution has resulted in some challenging conformance issues. In late 2014, a solution was executed to control this problem. Details of the diagnostic efforts and how this data was used to identify, characterize and mitigate an injector/producer connection through a void space conduit (VSC) will be outlined and discussed. These diagnostics include pressure transient analysis (PTA), interwell tracers, injection profiles, seismic mapping, fluid rate analysis, fluid composition and temperature monitoring. The importance of this data analysis is the key element necessary to select an effective solution.
The selected approach involved pumping a large tapered nitrified cement treatment into the offending injector, which is believed to be the single largest nitrified cement operation ever pumped within the oil industry. Because of extremely rapid communication with an offset producer, a protective gel was used to reduce the risk of cement entry into that producer. A brief review of alternative mitigation options and the reasons for selecting the nitrified cement treatment will be discussed. Additionally, a complete review of the shutoff technique, product, damage mitigation strategy, and complications associated with timing and coordination in an offshore environment will also be discussed. Finally, a summary of lessons learned, job execution observations, post-treatment performance results over the past three years, and forward plans will be presented. Based on these results it is believed that there are a number of opportunities to add strong value through conformance engineering.
Holubnyak, Yevhen (Kansas Geological Survey) | Watney, Willard (Kansas Geological Survey) | Hollenbach, Jennifer (Kansas Geological Survey) | Rush, Jason (Kansas Geological Survey) | Fazelalavi, Mina (Kansas Geological Survey) | Bidgoli, Tandis (Kansas Geological Survey) | Wreath, Dana (Berexco LLC)
Baseline geologic characterization, geologic model development, studies of oil composition and properties, miscibility pressure estimations, geochemical characterization, reservoir modelling were performed. In March of 2015 the injection well (class II) KGS 2-32 was drilled, cored, and logged through an entire anticipated injection interval. Whole core samples were obtained and tested for porosity and permeability, relative permeability, and capillary pressure. The Drill Stem Test (DST) was also conducted to estimate injection interval permeability and pore-pressure. After the injection well KGS 2-32 was acidized, Step Rate (SRT) and Interference (IT) tests were conducted and analysed for permeability, well pattern communication, and fracture closing pressure.
Approximately 20,000 metric tons of CO2 was injected in the upper part of the Mississippian reservoir to verify CO2 EOR viability in carbonate reservoirs and evaluate a potential of transitioning to geologic CO2 storage through EOR. Total of 1,101 truckloads, 19,803 metric tons, average of 120 tonnes per day were delivered over the course of injection that lasted from January 9 to June 21, 2016. After cessation of CO2 injection, KGS 2-32 well was converted to water injector and is currently continues to operate. CO2 EOR progression in the field was monitored weekly with fluid level, temperature, and production recording, and formation fluid composition sampling.
As a result of CO2 injection observed incremental average oil production increase is ~68% with only ~18% of injected CO2 produced back. Simple but robust monitoring technologies proved to be very efficient in detection and locating of CO2. High CO2 reservoir retentions with low yields within actively producing field could help to estimate real-world risks of CO2 geological storage.
Wellington filed CO2 EOR was executed in a controlled environment with high efficiency. This case study proves that CO2 EOR could be successfully applied in Kansas carbonate reservoirs if CO2 sources and associated infrastructure is available.
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.
Leon, J. M (Ecopetrol, S.A) | Izadi, M. (Ecopetrol, S.A) | Castillo, A. (Ecopetrol, S.A) | Zapata, J. F. (Ecopetrol, S.A) | Chaparro, C. (Ecopetrol, S.A) | Jimenez, J. (Ecopetrol, S.A) | Vicente, S. E. (Ecopetrol, S.A) | Castro, R. (Ecopetrol, S.A)
The Dina Cretaceous field, operated by Ecopetrol S.A., is located in the Upper Magdalena Valley (UMV) Basin in Colombia. The field discovered in 1969, reaching maximum primary oil rate of 6,500 BOPD in May 1980. Secondary recovery mainly by peripheral water injection started in 1986, achieving a maximum production of 9,850 BOPD in January 1988. Subsequently, water production has increased rapidly accompanied by declining oil production, due primarily to reservoir heterogeneity and an unfavorable mobility ratio. The oil recovery factor as of October 2017, as a percentage of OOIP, is estimated to be approximately 33% at a current water cut of about 97%.
Ecopetrol S.A in 2009, began to look for new development strategies that would allow optimizing the oil recovery for this asset. Several IOR/EOR technologies were screened to reduce water production and increase sweep efficiency. Polymer gels ("Conformance treatments"), polymer flooding and cross-linked polymer also known as Colloidal Dispersion Gels (CDG) are some of the technologies most commonly used during the last few decades for this purpos. Based on screening study, detailed production and injection data analysis, water channeling, reservoir heterogeneity, adverse mobility ratio, laboratory evaluation and simulation results, the cross-linked polymer systems (CDG) were implemented in four patterns between 2011 and 2015. This would allow to increase the volumetric sweeping efficiency both for mobility control, in-depth conformance control and leading to viable project both technically and economically.
This paper presents the implementation and results of the injection of cross-linked polymer systems in the Dina Cretaceous field. A summary of the maturation process is presented, from conceptual design, experimental evaluation, engineering analysis, numerical simulation, pilot execution, process monitoring and field expansion strategy, as well as the results obtained in the pilot.
The results of the pilot were satisfactory both technically and economically and lead to a new development plan for the field. This new plant is focused on the optimization of the waterflood, pattern reconfiguration, infill drilling, selective injection, and improving the sweep efficiency through the injection of cross-linked polymer across the field in 11 more patterns.
Yuan, Qingwang (University of Regina) | Wang, Shuoshi (University of Oklahoma) | Wang, Jinjie (China University of Geosciences) | Zeng, Fanhua (University of Regina) | Knorr, Kelvin D. (Saskatchewan Research Council) | Imran, Muhammad (Saskatchewan Research Council)
The frontal instabilities are a key control factor which can significantly affect the sweep efficiency and oil recovery in miscible flooding processes. Under unfavorable viscosity ratio between injection solvent and oil, the frontal instabilities are nearly unavoidable. However, how to suppress the instabilities, especially with low additional costs, should be carefully investigated. The present study examines the time-dependent displacement rates on flow instabilities in miscible flooding. Within the capacity of injection pumps, the injection rates are varied with time in a fast alternating manner. It is found that this kind of variable rates can stabilizing frontal instabilities by enhancing initial uniform mixing of solvent and oil. It therefore suppresses the later development of instabilities. Eventually, a much less unstable front is obtained when compared with the constant injection rate. Other parameters such as the amplitude of rates are also examined. The variations of propagation of front with time are analyzed for the change of rate strength. It is can therefore be concluded that this kind of time-dependent rate can improve oil recovery at very low additional rate within the capacity of pumps for the field EOR processes.
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.
Trujillo, M. (Ecopetrol S. A) | Delgadillo, C. (Ecopetrol S. A) | Niz-Velásquez, E. (Universidad Industrial de Santander) | Claro, Y. (Ecopetrol S. A) | Rodriguez, E. (Ecopetrol S. A) | Rojas, R. (Ecopetrol S. A)
Prior to starting any Enhanced Oil Recovery (EOR) process, it is desirable to characterize the flow pattern within the affected reservoir volume. This becomes of critical importance for in situ combustion in heavy oil reservoirs, where the mobility ratio is highly unfavorable, oftentimes resulting in channeling or early breakthrough. An inter-well connectivity test through immiscible gas injection aids in characterizing the flow distribution, in addition to: 1) calibrating estimates for sweep efficiency, 2) evidencing geological features that may lead to preferential flow towards a particular well or group of them, or lack of connection amongst them, 3) creating a gas path between the injector and producer wells to enable a safe progression of the combustion front, and 4) evaluating the performance of artificial lift and well control systems under high gas-liquid ratio conditions.
A connectivity test using nitrogen was designed, implemented and evaluated at the Chichimene field, prior to the ignition of the in situ combustion pilot. This process is summarized and described in this paper. This will be the first in situ combustion trial in a deep (≈ 8,000 ft), extra-heavy oil reservoir, and will serve as a data source to evaluate the development of resources under similar conditions in the eastern plains basin of Colombia. This set of reservoirs bears a significant fraction of the hydrocarbon resources in the country and under Ecopetrol operation.
The importance of this pilot makes this connectivity test of even larger relevance to reduce the subsurface and operational uncertainty, identify risks, and increase the probability of success of the combustion process as an option to economically producing these resources.
Wang, Yang (China University of Petroleum – Beijing and Pennsylvania State University) | Cheng, Shiqing (China University of Petroleum – Beijing) | Zhang, Kaidi (Lusheng Petroleum Development Co., Ltd, SINOPEC Shengli Oilfield Company) | Xu, Jianchun (China University of Petroleum – East China) | Qin, Jiazheng (China University of Petroleum – Beijing) | He, Youwei (China University of Petroleum – Beijing and Texas A&M University) | Luo, Le (China University of Petroleum – Beijing) | Yu, Haiyang (China University of Petroleum – Beijing)
Pressure-transient analysis (PTA) of water injectors with waterflood-induced fractures (WIFs) is much more complicated than hydraulic fracturing producers due to the variation of fracture properties in the shutting time. In plenty of cases, current analysis techniques could result in misleading interpretations if the WIFs are not well realized or characterized. This paper presents a comprehensive analysis for five cases that focuses on the interpretation of different types of pressure responses in water injectors.
The characteristic of radial composite model of water injector indicates the water erosion and expansion of mini-fractures in the inner region. The commonplace phenomena of prolonged storage effect, bi-storage effect and interpreted considerably large storage coefficient suggest that WIF(s) may be induced by long time water injection. Based on this interpreted large storage coefficient, fracture half-length can be obtained. In the meanwhile, the fracture length shrinks and fracture conductivity decreases as the closing of WIF, which has a considerable influence on pressure responses. Results show that the upward of pressure derivative curve may not only be caused by closed outer boundary condition, but also the decreasing of fracture conductivity (DFC). As for multiple WIFs, they would close successively after shutting in the well due to the different stress conditions perpendicular to fracture walls, which behaves as several unit slopes on the pressure derivative curves in the log-log plot.
Aiming at different representative types of pressure responses cases in Huaqing reservoir, Changqing Oilfield, we innovatively analyze them from a different perspective and get a new understanding of water injector behaviors with WIF(s), which provides a guideline for the interpretation of water injection wells in tight reservoirs.