Foamy oil flow is commonly encountered in heavy oil production from homogeneous or heterogeneous (after cold heavy oil production with sands - CHOPS) reservoirs. This can be due to a drive mechanism in the primary production (depletion of methane saturated heavy-oil) and secondary stage (gas injection after primary production). In the primary stage, among other important parameters, pressure depletion rate has been reported to be the most critical characteristic to control this type of flow. In the secondary stage, gas amount and type (sole injection of methane, carbon dioxide, propane, or combination of these) and application conditions (soaking time on cyclic solvent injection durations, depletion rate) are critical. The cornerstone of the foamy oil behavior relies on its stability, which depends on parameters such as oil viscosity, temperature, dissolved gas ratio, pressure decline rate, and dissolved gas (solvent) composition. Although the process has been investigated and analyzed for different parameters in the literature, the optimal conditions for an effective and more economical process (mainly foamy oil stability) has not been thoroughly understood, especially for the secondary recovery conditions. In this study, air has been used as an ameliorative to improve foamy oil stability. Five pressure depletion tests divided into two cases were performed. Each pressure depletion test included eight independent pressure recordings obtained from pressure transducers distributed along a sandpack holder for 48 hours. In order to reach the optimal conditions of the applications, three different pressure depletion rates were tested at 0.23 psi, 0.51 psi/min, 1.53 psi/min, and air were tested as an ameliorative for foamy oil stability. We observed that increasing pressure depletion rates increase the formation of foamy oil, however, when pressure depletion rates were too high, it may cause a negative effect in the final oil recovery factor. We also observed that injecting air into the sandpack caused an increase in the heavy oil viscosity, and the subsequent injection of methane as a solvent became more effective in generating more stable foamy oil, which resulted in obtaining a higher oil recovery factor. This novel approach is expected to improve the understanding and the use of foamy oil mechanics and to achieve a higher foamy oil stability aiming to increase the final heavy oil recovery factor.
Hamidpour, Esmaeil (National Iranian South Oil Company) | Fathollahi, Sadegh (National Iranian South Oil Company) | Mirzaei-Paiaman, Abouzar (National Iranian South Oil Company) | Bardestani, Majid (National Iranian South Oil Company) | Kamalifar, Hadis (National Iranian South Oil Company)
Simulation of fractured reservoirs is an old headache in oil industry, especially for reservoirs located in southern west of Iran. The situation is much more complex when dealing with heavy oil. Most of the simulation results are not reliable due to the many uncertainties in the data related to fractured reservoirs, especially characterizing the flow of heavy fluids in fractures. Consequently, the oil administration is unable to forecast a near-to-reality future of reservoirs. Due to the long run time and technical constraints in single porosity method which is used for fractured reservoirs, a much faster dual porosity algorithm is suggested for simulation of fractured reservoirs. Till now, the single porosity method is used to validate the corresponding dual porosity algorithm.
Oil production in fractured reservoirs is controlled by special mechanisms e.g. capillary imbibition, gravity drainage and etc. Capillary imbibition can be occurred co-currently, counter-currently or both together. These two are different significantly in both their rate of imbibition and their ultimate oil recoveries. Counter-current imbibition is slower than co-current imbibition and the ultimate oil recovery is also lower in some extent. This is due to the difference in their boundary condition and relative permeability. Both of co/counter-current imbibition can be occurred in water injection around a matrix block. Counter-current imbibition is more active when dealing with heavy reservoir fluid. Hence, studying the effect of simultaneous counter-current spontaneous imbibition (COUCSI) and co-current spontaneous imbibition (COCSI) in heavy oil reservoirs is necessary.
We have come to the point that for having systematic evaluations of simulating methods each mechanism should be introduce to the simulator exclusively. To do this, there should be a thorough understanding of the process and consequently expected behaviors of the model should be specified in full details. Therefore, first of all some recent experimental researches are investigated carefully. Then to see the dimensions of the errors related to simulations, a carefully designed model is used to see the performance of the simulator in accounting of oil production under capillary imbibition mechanism. Two matrix blocks are set one above each other and also they are surrounded by fractures. The water then is injected from the bottom and liquids will be produce from the top in a way that constant voidage requirement is met. By this constraint, total pressure drop is negligible and the viscous displacement is of no significance. Accordingly, the process is controlled by capillarity. After full description of single porosity model and understanding its capability in simulating water injection controlled by capillarity, then an equivalent dual porosity model is generated and compared to the single porosity simulation.
Finally the equation that is developed for relating the counter-current relative permeability to the co-current relative permeability (
Taura, Usman (Sultan Qaboos University) | Mahzari, Pedram (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Sohrabi, Mehran (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Al-Wahaibi, Yahya (Sultan Qaboos University)
In heavy oil displacement by gas, chemical, or water injection, severe instability can occur due to adverse mobility ratio, gravity or compositional effects. However, most analytical methods for estimation of relative permeability such as JBN, assume a stable front in the displacement. This implies that such methods cannot be applied to estimate relative permeability when the displacement is severely unstable.
A common approach for estimation of relative permeability in displacement with instability involves the history matching of a 2D or 3D high resolution, fine scale models of the displacement. However, this is also impractical due to associated high computational cost.
This work describes a fast methodology for the estimation of relative permeability functions in displacement with instability and compositional effect using multi coarse-scale models. It involves the history matching of a set of coarse grid models of the unstable displacement and correlating the parameter a relative permeability function (L.E.T) in order to estimate the relative permeability of the corresponding high-resolution model. By this approach, an attempt was made to resolve the fine-scale information without direct solution of the global fine-scale problem. Hence, an unstable displacement can be modelled using a coarse grid model which has a relatively lower computational cost.
The results showed that the approach is three times faster, and required less than half the memory of a conventional method.
Beheiry, Karim (Halliburton) | Al Mulaifi, Mohammed (Kuwait Oil Company) | Sekhri, Anish (Kuwait Oil Company) | Farhi, Nadir (Halliburton) | Nouh, Walid (Halliburton) | Abdel Naby, Ahmed (Halliburton) | Marafi, Abdullah (Kuwait Oil Company) | Shatta, Atef (Kuwait Oil Company) | Al-Ali, Hussain (Kuwait Oil Company)
The 12-1/4-in. directional application is one of the most challenging applications in North Kuwait. The section requires drilling from the Mutriba (Santonian) to Burgan (Albina) formations through highly interbedded, high-compressive-strength carbonates (limestone and dolomite), sandstones, and shales. In recent years, Kuwait Oil Company (KOC) has tested many different bit designs in an attempt to minimize stick/slip vibrations and maximize the rate of penetration (ROP). This paper presents the technology used to nearly eliminate stick/slip vibrations, leading to a field record (and a consistent performance) for this application, as well as the process used to develop the technology.
The interval was drilled using a rotary steerable system (RSS) to maximize wellbore quality and to provide consistent build-up rates (BUR) required. Parameters run in this application are often limited because stick/slip becomes uncontrollable when transitioning through the many formation types. In addition, reactive and stressed caving shales are regularly observed in the Ahmadi and Wara formations drilled during the interval. Special care is needed to mitigate these drilling challenges and to successfully drill the interval with low stick/slip vibrations and high ROP.
Using proprietary state-of-the-art design and analysis technologies, a new polycrystalline diamond compact (PDC) bit was designed for use specifically with RSS tools to minimize the vibrations. The solution required a thorough offset analysis before the interval that was presented using the design process. The design process enabled the presentation of a driller's roadmap to be used in conjunction with the new bit to enable a benchmark ROP to be achieved.
The use of the newly designed PDC bit produced minimal torsional vibrations, enabling a 62% increase in ROP over the field average. This increased ROP resulted in a savings of USD 90,000, reducing the cost per foot by 33%, as compared to the field average. The bit also came out in excellent condition, enabling future use in similar applications for KOC.
Kumar, Anjani (Computer Modelling Group Ltd) | Novlesky, Alex (Computer Modelling Group Ltd) | Bityutsky, Erykah (Computer Modelling Group Ltd) | Koci, Paul (Consultant for Occidental Petroleum Corporation) | Wightman, Jeff (Occidental Petroleum Corporation)
Heavy oil reservoirs often require thermal enhanced oil recovery (EOR) processes to improve the mobility of the highly viscous oil. When working with steam flooding operations, finding the optimal steam injection rates is very important given the high cost of steam generation and the current low oil price environment. Steam injection and allocation then becomes an exercise of optimizing cost, improving productivity and net present value (NPV). As the field matures, producers are faced with declining oil rates and increasing steam oil ratios (SOR). Operators must work to reduce injection rates on declining groups of wells to maintain a low SOR and free up capacity for newer, more productive groups of wells. Operators also need a strong surveillance program to monitor field operational parameters like SOR, remaining Oil-in-Place (OIP) distribution in the reservoir, steam breakthrough in the producers, temperature surveys in observation wells etc. Using the surveillance data in conjunction with reservoir simulation, operators must determine a go-forward operating strategy for the steam injection process.
The proposed steam flood optimization workflow incorporates field surveillance data and numerical simulation, driven by machine learning and AI enabled Algorithms, to predict future steam flood reservoir performance and maximize NPV for the reservoir. The process intelligently determines an optimal current field level and well level injection rates, how long to inject at that rate, how fast to reduce rates on mature wells so that it can be reallocated to newly developed regions of the field. A case study has been performed on a subsection of a Middle Eastern reservoir containing eight vertical injectors and four sets of horizontal producers with laterals landed in multiple reservoir zones. Following just the steam reallocation optimization process, NPV for the section improved by 42.4% with corresponding decrease in cumulative SOR by 24%. However, if workover and alternate wellbore design is considered in the optimization process, the NPV for the section has the potential to be improved by 94.7% with a corresponding decrease in cumulative SOR by 32%. This workflow can be extended and applied to a full field steam injection project.
Sun, Fengrui (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Yao, Yuedong (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Li, Guozhen (China University of Petroleum) | Qu, Shiyuan (China University of Petroleum) | Zhang, Shikun (China University of Petroleum) | Shi, Yu (China University of Petroleum) | Xu, Zhengming (China University of Petroleum) | Li, Xiangfang (China University of Petroleum)
Great breakthrough has been made in heavy oil EOR mechanism under water injection at different state. New findings from both experimental and theoretical studies provide strong support for the broad application prospect of steam in heavy oil EOR. In this paper, a series of studies are carried out on productivity of a horizontal well with several vertical steam injectors during the steam-assisted-gravity-drainage (SAGD) process.
In this paper, a novel topic is discussed on the effect of steam state on oil productivity during the SAGD process. The injection wells are three parallel vertical wells and the production well is a horizontal well. The numerical method is adopted to reveal the physical aspect mechanisms. Some meaningful conclusions are listed below.
(a) The usefulness of superheated steam in heavy oil recovery lays in its chemical reactions with heavy oil and rock minerals. The effect of physical heating on oil recovery efficiency is weak. (b) The oil production rate at the starting stage, from 0 day to 30 day, is oscillating with time due to the fact that the preheating stage is neglected. The connectivity between injectors and producer is poor without a necessary step of preheating. (c) The direction of oil recovery is from well-bottom of the injector to the well-head and then to the places between the injectors. (d) Chemical reactions may play an important role in oil recovery efficiency if the final recovery efficiency by injecting steam with higher steam quality is several order of magnitude than that by injecting steam with lower steam quality.
We carried out the pilot study on the effect of steam state on heavy oil EOR during the SAGD process with several vertical injectors. More importantly, the pilot study conducted in this paper provide the very basis for the application of superheated steam for oil companies and following academic research in the field.
Kharghoria, Arun (Kuwait Oil Company) | Garcia, Jose Gregorio (Kuwait Oil Company) | AlRasheedi, Khaled Saleh (Kuwait Oil Company) | Al-Rabah, Abdullah Abdul Karim (Kuwait Oil Company) | Sanwoolu, Ayodele Olusegun (Kuwait Oil Company) | Husain, Hisham (Shell)
This study presents an assessment of heterogeneity on vertical and areal scales and discusses the development of methodology for a proposed waterflood scheme in a heavy oil field in Northern Kuwait. The field produces average 15 API crude of 50-100 cp at 100 F. The field has a complex geologic and stratigraphic architecture, and the associated reservoirs are highly heterogeneous in nature. Both numerical simulation and analytical models were used to assess the performance of the proposed waterflood. Vertical and areal heterogeneity of the oil bearing formation were evaluated using Dykstra-Parsons coefficient, Lorenz coefficient and coefficient of variance methodologies. Both numerical simulation and analytical models were deployed to evaluate the waterflood performance under 5-spot and inverted 9-spot patterns for 20 and 10 acre spacing. An analytical excercise was carried out as a pre-check for the expected waterflood recovery factors. Results from all three methods of heterogeneity assessment indicated the existence of a highly heterogeneous reservoir with average Dykstra-Parsons coefficients being greater than 0.8. A heterogeneity distribution map shows strong presence of areal heterogeneity.
Alhuraishawy, Ali K. (Missan Oil Company / Reservoir and Fields Development Directorate) | Bai, Baojun (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Al-Bazzaz, Waleed H. (Kuwait Institute for Sciencefic Research)
Waterflooding with different inonic composition called advanced ion management which play a role with ionic composition of injected water to enhance the oil production. In the last decate, many studies pointed out that the composition of injected water could changes rock wettability during waterflooding. The main purpose of this study is to evaluate the effects of SO4 and low salinity water on improving oil recovery in oil-wet carbonate reservoirs. Sulfate ion concentration, low salinity water, rock composition, porosity, and permeability were examined using a designed model. Typical seawater, increase SO4, two and three times in the seawater, and low salinity water that had been diluted 10 and 100 times were applied as waterflooding processes with three different average matrix permeability. Oil recovery factor improved as sulfate ion concentration increased and water salinity decreased by changing core wettability with greater water-wet conditions. Morover, the diluted seawater has more effect than sulfate ion concentration when a carbonate core has a few percentage of silica. Sulfate ion concentration performance increased with porosity and temperature, and the dilute seawater showed more effect at high temperature. Increased sulfate ion concentration followed by diluted sea water with present silica in the core composition might be a viable technique to improve oil recovery in the carbonate reservoir. The experimental results validated by field-scale simulation study and provides deep insight into understanding of advanced ion management performance.
Alfarge, Dheiaa (Iraqi Ministry of Oil, Missouri University of Science and Technology) | Alsaba, Mortadha (Australian College of Kuwait) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
Over the last decade, Unconventional Liquids Rich Reservoirs (ULR) have become the main target for oil and gas investors as conventional formations started to deplete and diminish in numbers. These unconventional plays have a huge oil reserve; however, the primary oil recovery factor is predicted to be less than 10%. Unconventional Improved Oil Recovery (UIOR) techniques are still a new concept in the oil industry since there is no commercial project reported for any IOR technique yet. Miscible gas based EOR technique might be the most potential strategy to improve oil recovery in such complex plays.
In this study, a comprehensive and critical review has been conducted to evaluate the feasibility of miscible gas based EOR technique in ULR. The reports and studies from three different approaches (lab, simulation and pilot tests) were summarized and combined to provide in-depth insights and lessons learned from the applicability of miscible gas based EOR in ULR. Firstly, the main problems in the previous lab and simulation approaches, which were used to investigate the viability of different EOR methods, have been diagnosed. Secondly, the performance of injecting different miscible gases to enhance oil recovery in the pilot tests conducted in ULR has been extensively discussed. Thirdly, the physical and chemical reasoning behind the performance gap for the injected gases in the lab scale versus the field scale of ULR been diagnosed.
This study reported that most of the previous lab and simulation approaches suffered from significant lacks and drawbacks, which created a clear gap in the performance of the injected gases in the lab scale versus the field scale. This research clearly found that the performance of Natural Gas (NG) injection is significantly better than the performance of CO2 injection in terms of enhancing oil recovery in the field pilots. This study also found that the production response of unconventional reservoirs to the injected NGs is much faster than that for the injected CO2. Combining the pilot tests data and simulation studies showed that the number of cycles in huff-n-puff operations has a negative impact on CO2-EOR while it has a positive impact on NGs-EOR. Finally, this research provided deep insights on what the operators can expect from the EOR performance by injecting different miscible gases in the lab scale versus the field scale of ULR.
Lower Fars heavy oil <16 °API is considered a type of conventional heavy oil, which will be considered as priority petroleum production system for future heavy oil recovery in Kuwait. These types of oils are abundant in great amounts in Ratga field North Kuwait, yet expensive to produce due to its high viscosity hence low mobility underground. Kuwait strategy is shifting focus to these types of oils since conventional medium oil and other less-quantitative-light-oil reservoirs are continuously depleting. The study's interest is directed towards a specific type of EOR oil, which is hot dry air sequestration into Lower Fars heavy oil. This study presents novel heavy oil recovery method for 14 °API crude oil using hot dry air as well as their potential recoveries. All recoveries considered for this study are bench-scale laboratory physical experiments with horizontal (0 °), vertical (90 °), and directional (45 °) continuous air diffusion augmented with applied different thermal heat treatments.
The main objective for this research is to model recovery efficiency from this hot dry heat diffusion technique (HDAD). This technique will produce air diffusion design. This design will consider direction of blow diffusion for three possible well orientations: horizontal 0 degrees, vertical 90 degrees, and directional 45 degrees. Also, the design will consider six temperatures: 27 °C 30 °C 60 °C 70 °C 85 °C and 100 °C dry hot air diffusions. Moreover, the design will consider two diffusion velocities 74.08 km/hr and 111.12 km/hr. These velocities will determine designing the time of recovery, which is one hour, according to lab-time limitations and permissions. The main technology motivation for hot dry air diffusion (HDAD) research is finding the optimized economical EOR recovery efficiency factor that will extract most of 14 °API Lower Fars oil. The model determines the recovery potential factor in a classic, optimum and conventional economic scenario considering the energy usage to generate the hot dry air delivered to the reservoir. Also, HDAD technology usages will avoid the use of water technologies recoveries. Avoiding water technology recovery will minimize environmental impact, crude oil/ emulsions subsurface-mobility issues and costly water production management used at current steam economic challenges.