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Results
A New Adaptive Implicit Method for Multicomponent Surfactant-Polymer Flooding Reservoir Simulation
Batista Fernandes, Bruno Ramon (The University of Texas at Austin (Corresponding author)) | Sepehrnoori, Kamy (The University of Texas at Austin) | Marcondes, Francisco (Federal University of Ceará) | Delshad, Mojdeh (The University of Texas at Austin)
Summary In the oil industry, chemicals can improve oil production by mobilizing trapped and bypassed oil. Such processes are known as chemical-enhanced oil recovery (CEOR). Surfactants and polymers are important chemicals used in CEOR with different mechanisms to improve oil recoveries, such as reduction in residual saturation, oil solubilization, and mobility control. However, both surfactant and polymer may increase the cost of oil production, making optimizing these processes essential. Reservoir simulators are tools commonly used when performing such field optimization. The simulation of surfactant flooding processes has been historically performed with the implicit pressure explicit composition (IMPEC) approach. The injection of surfactants requires modeling the brine/oil/microemulsion phase behavior along with other processes, such as capillary desaturation and retention. The microemulsion phase behavior and the complex relative permeability behavior can lead to convergence issues when using fully implicit (FI) schemes. Only recently, the FI approach has been efficiently applied to simulate this process using new modeling. The adaptive implicit method (AIM) can combine the benefits of the FI and IMPEC approaches by dynamically selecting the implicitness level of gridblocks in the domain. This work presents a new AIM in conjunction with recently developed models to mitigate discontinuities in the microemulsion relative permeabilities and phase behavior. The approach presented here considers the stability analysis method as a switching criterion between IMPEC and FI. To the best of our knowledge, the approach presented here is the first AIM to consider the brine/oil/microemulsion three-phase flow in its conception. The new approach uses the finite volume method in conjunction with Cartesian grids as spatial discretization and is applied here for field-scale problems. The new approach is tested for polymer flooding and surfactant-polymer (SP) flooding for problems with several active cells ranging from about a hundred thousand to almost a million. The AIM approach was compared with the FI and IMPEC approaches and displayed little variation in the computational performance despite changes in the timestep size. The AIM also obtained the fastest performance for all cases, especially for SP flooding cases. Furthermore, the results here suggest that the gap in performance between the AIM and FI seems to increase as the number of gridblocks increases.
- North America > United States > Texas (1.00)
- Asia (0.93)
- Overview (0.54)
- Research Report > New Finding (0.46)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Microfluidics for Carbonate Rock Improved Oil Recovery: Some Lessons from Fabrication, Operation, and Image Analysis
Duits, Michel H. G. (University of Twente, Physics of Complex Fluids Group (Corresponding author)) | Le-Anh, Duy (University of Twente, Physics of Complex Fluids Group) | Ayirala, Subhash C. (Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC)) | Alotaibi, Mohammed B. (Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC)) | Gardeniers, Han (University of Twente, Mesoscale Chemical Systems Group) | Yousef, Ali A. (Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC)) | Mugele, Frieder (University of Twente, Physics of Complex Fluids Group)
Summary After the successful implementation of lab-on-a-chip technology in chemical and biomedical applications, the field of petroleum engineering is currently developing microfluidics as a platform to complement traditional coreflooding experiments. Potentially, microfluidics can offer a fast, efficient, low-footprint, and low-cost method to screen many variables such as injection brine composition, reservoir temperature, and aging history for their effect on crude oil (CRO) release, calcite dissolution, and CO2 storage at the pore scale. Generally, visualization of the fluid displacements is possible, offering valuable mechanistic information. Besides the well-known glass- and silicon-based chips, microfluidic devices mimicking carbonate rock reservoirs are currently being developed as well. In this paper, we discuss different fabrication approaches for carbonate micromodels and their associated applications. One approach in which a glass micromodel is partially functionalized with calcite nanoparticles is discussed in more detail. Both the published works from several research groups and new experimental data from the authors are used to highlight the current capabilities, limitations, and possible extensions of microfluidics for studying carbonate rock systems. The presented insights and reflections should be very helpful in guiding the future designs of microfluidics and subsequent research studies.
- North America > United States (1.00)
- Asia > Middle East (0.67)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.81)
- Geology > Mineral > Carbonate Mineral > Calcite (0.53)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
General Optimization Framework of Water Huff-n-Puff Based on Embedded Discrete Fracture Model Technology in Fractured Tight Oil Reservoir: A Case Study of Mazhong Reservoir in the Santanghu Basin in China
Xiang, Yangyue (School of Earth Resources, China University of Geosciences, Wuhan) | Wang, Lei (School of Earth Resources, China University of Geosciences, Wuhan (Corresponding author)) | Si, Bao (Tuha Oilfield Company, Petro China, Hami) | Zhu, Yongxian (Tuha Oilfield Company, Petro China, Hami) | Yu, Jiayi (Research Institute of Exploration and Development, Tuha Oilfield Company, Petro China, Hami) | Pan, Zhejun (Key Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient Development, Ministry of Education, Northeast Petroleum University, Daqing)
Summary Water injection huff-n-puff (WHnP) is currently an important technology to improve the recovery of tight reservoirs. On the one hand, this technology can replenish the formation energy, and on the other hand, it can effectively replace the oil in a tight reservoir. In this paper, the effect of WHnP on cumulative oil production and oil increase rate is simulated and analyzed by comparing depleted development and WHnP scenarios, using numerical simulation methods. A field-scale numerical simulation was modeled based on typical fluid, reservoir, and fracture characteristics of Mazhong tight oil, coupled with geomechanical effects, stress sensitivity, and embedded discrete fractures. The result of different WHnP cycles is studied, and the limiting WHnP cycle is determined to be four cycles. The WHnP efficiency is compared for different permeability scales from 0.005 to 1 md, and it is determined that WHnP at a permeability of 0.01 md resulted in the largest production enhancement. Subsequently, sensitivity studies are conducted using an orthogonal experimental design for six uncertain parameters, including the WHnP cycle, production pressure difference, permeability, natural fracture density, hydraulic fracture half-length, and conductivity. The results show that throughput period and permeability are important parameters affecting cumulative oil production, and permeability and natural fracture density are important parameters affecting oil increase rate. In addition, contour plots of permeability and WHnP cycle, hydraulic fracture half-length, and conductivity are generated. Based on these plots, the optimal conditions with better enhanced recovery results in different WHnP scenarios can be easily determined. This study can better solve the problems encountered in WHnP of tight reservoirs and provide a theoretical basis for stable and efficient development.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.42)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.35)
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211167, “Selective and Reversible Water-Shutoff Agent Based on Emulsion System With Nanoparticles Suitable for Carbonate Reservoirs at High-Temperature and High-Salinity Conditions,” by Masashi Abe, SPE, Jumpei Furuno, and Satoru Murakami, Nissan Chemical Corporation, et al. The paper has not been peer reviewed. _ The complete paper presents the evaluation results of a water-shutoff (WSO) agent based on an emulsion-type chemical material with nanoparticles. The WSO agent, which the authors call an emulsion system with nanoparticles (ESN), has several advantages to existing polymer and gel materials, including high thermal stability, low sensitivity to mineralization, thixotropic characteristics, selectivity of blocking effects for oil and water, and reversibility of blocking effects. In WSO applications, these properties of ESN could be well-suited for improved oil recovery. Introduction ESN is recognized as a proven technology for carbonate reservoirs. However, the reservoir under study did not feature harsh conditions; therefore, this work evaluated ESN potential for carbonate reservoirs in the UAE typically having high-temperature and high-salinity conditions. A primary purpose of the technology, aside from improved oil recovery, is contributing to greenhouse-gas emission reduction and building competitive low-CO2-intensity oil-brand value. In general, produced water volume dramatically increases in maturing oil fields. Reducing water production also can contribute to saving water injection from a reservoir-voidage-replacement viewpoint. Therefore, the functional chemical WSO concept has a significant effect on contributing to the International Energy Agency’s sustainable development scenario. Materials and Physicochemical Property Tests Oil, Water, and Carbonate Core. Dead oil is sampled from an offshore carbonate field in the Middle East containing light crude oil (32.3 °API). Brine and plug core properties are summarized in Tables 1 and 2 of the complete paper. For thermal-stability tests, both brines were used for making the ESN. The WSO coreflood tests used the ESN made with injection water. Advanced Features of ESN. Rheology. The viscosity of ESN is controllable by changing the water/oil ratio; viscosity becomes lower with increasing oil content and higher with increasing water content. These components were stirred, and two ESN samples were prepared using Crude Oil A (from Oil Field A, UAE) or diesel oil. The samples are referred to as Crude Oil A-based ESN and Diesel Oil-based ESN in this paper. Both ESN samples showed similar viscosity curves; such thixotropic characteristics are an important property of ESN. ESN is flowable at stirring conditions. In particular, the viscosity of ESN can be decreased to less than 50 cp at high shear rates, so it can be injected into the reservoir by pumping. On the other hand, ESN becomes highly viscous and less flowable when no energy is applied to it (the ESN surface looks semisolid in this condition). In field operations, the viscosity of ESN decreases depending on the pressure generated by injection pumps on the surface. However, the injection pressure also releases in a radial direction from the bottomhole zone. As a result, ESN recovers a high-viscosity state because of decreasing shear rate with pressure release.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Development of Novel Thermoactive Polymer Compositions for Deep Fluid Diversion Purposes
Veliyev, E. F. (OilGasScientificResearchProject, Institute, SOCAR, Baku, Azerbaijan / Composite Materials Scientific Research Center, Azerbaijan Sate University of Economics, Azerbaijan) | Aliyev, A. A. (OilGasScientificResearchProject, Institute, SOCAR, Baku, Azerbaijan) | Poladova, G. Sh. (OilGasScientificResearchProject, Institute, SOCAR, Baku, Azerbaijan)
Oil and gas production is a vital component of the global economy, serving as the primary source of hydrocarbons, which are not only essential for various products but also as the primary energy source. Global energy consumption, as reported by the International Energy Agency (IEA), has been steadily increasing due to population growth and improved living standards, with a 2.9% increase in 2019, surpassing the 1.9% average annual growth rate of the previous decade [1]. Despite the growing interest in renewable energy resources, they currently represent a small portion of the global energy mix. In 2020, fossil fuels still dominated electricity production in the United States, accounting for approximately 80%, while renewables contributed around 20% [2, 3]. Additionally, renewable energy sources face challenges such as environmental dependence, high initial costs, and environmental consequences related to their production. In light of these circumstances, hydrocarbon production remains crucial to meet the rising energy demand, achieved through the exploration of new reservoirs or enhancing the productivity of existing ones. Exploring new reservoirs is resource-intensive and often located at greater depths, necessitating innovative technologies [4-5].
- North America > United States (0.35)
- Asia > Azerbaijan (0.32)
- Production and Well Operations (1.00)
- Health, Safety, Environment & Sustainability > Environment (0.89)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.72)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.69)
Abstract To unlock Mishrif reservoir potential in West Kuwait, a new development strategy involving analysis with Distributed Temperature Sensing (DTS) and downhole intervention with instrumented coiled tubing (Active CT) followed by high-rate stimulation by bull-heading has been applied to the tight carbonate formation. The goal was to find a cost-effective stimulation strategy that would increase the number of productive wells through an integrated production enhancement project approach. The operation encountered various challenges, primarily driven by a high-permeability areas across the open hole, which was detected by DTS. Modifications were made to the CT stimulation procedure, including diversion techniques such as high-pressure jetting, dual injection and the pumping of a near-wellbore fully degradable diverter composed of a customized blend of multimodal particles and degradable fibers to temporarily isolate the highly permeable streaks. Real-time downhole telemetry had a paramount importance in ensuring the injection rate was kept below preset pressure limits and in monitoring downhole dynamics for optimal use of the high-pressure jetting tool. In most of the interventions, following the CT stimulation, a second post-stimulation DTS log was conducted to evaluate the fluid coverage and effectiveness of the diversion strategy allowing for further adjustment of the bullhead stimulation program for an optimum fluid coverage and avoiding the high-intake zones.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Najmah Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Minagish Field > Marrat Formation > Upper Marrat Formation > Marrat "C" Formation (0.99)
- (13 more...)
Binary Mixture Thermo-Chemical (BiMTheCh) Technology for Development of Low-Permeable Formations of Oil Fields in Caspian Sea
Koochi, M. Rezaei (Petroleum engineering department, Kazan Federal University, Russia) | Rojas, A. (Petroleum engineering department, Kazan Federal University, Russia) | Varfolomeev, M. A. (Petroleum engineering department, Kazan Federal University, Russia) | Khormali, A. (Chemistry department, Gonbad Kavoos University, Iran) | Lishcuk, A. N. (HMS Group Company, Moscow, Russia)
Abstract Binary mixture thermo-chemical (BiMTheCh) technology refers to energy-releasing chemicals which can be injected into the reservoir with in-situ generation of heat, nitrogen and carbon dioxide. As laboratory investigations show, BiMTheCh or thermochemical fluid has proved to be a highly effective technology for stimulation of oil wells with heavy oil and low permeability. In this work, the feasibility of this technology for stimulation of brown fields from laboratory to field scale is investigated. First, on the laboratory scale, thermobaric parameters of the reaction were studied to optimize the composition of injecting chemicals. And finally, the optimized composition is applied to enhance oil recovery from low permeable reservoirs in Russia. Laboratory results show that BiMTheCh can be used for removing asphaltene and resin from near borehole zone by melting them. Generated gases after the reaction create a network of fractures in the vicinity of the reaction zone and simultaneously, by inducing a thermobaric shock, cracks oil molecules and upgrades oil directly into the reservoir. Oil field data in 5 wells shows that oil production increased 2-3 folds with a duration of 12 months or more. BiMTheCh can be used for stimulation of green and brown fields with a high efficiency in a safe rig-less mode.
- North America > United States > Texas (1.00)
- Europe (1.00)
- Asia (1.00)
Experimental Study on Nano Polymer Microspheres Assisted Low Salinity Water Flooding in Low Permeability Reservoirs
Yuan, W. (China University of Petroleum-Beijing) | Hou, J. (China University of Petroleum-Beijing) | Yang, Y. (China University of Petroleum-Beijing) | Zhao, Y. (China University of Petroleum-Beijing) | Nie, H. (PetroChina Southwest Oil & Gasfield Company)
Abstract Water flooding in low permeability reservoirs generally results in severe channeling and a large amount of remaining oil. Polymer microspheres and low-salinity water are proven practical approaches for profile control and oil displacement, respectively, and their combination is expected to achieve both effects. This paper evaluates the co-injection of nano-polymer microspheres and low salinity water and its impacts on oil displacement in low permeability reservoirs. Firstly, the influence of injection velocity and injection concentration on the plugging effect of nano-polymer microspheres was evaluated by core displacement experiments. Secondly, the nano-polymer microsphere solutions were prepared using 10-time and 100-time diluted formation water to evaluate the impacts of the co-injection of nano-polymer microspheres and low-salinity water. Meanwhile, the Nuclear Magnetic Resonance T2 spectrum and imaging test were used to reveal the extent of residual oil in pores of various sizes during core flooding as well as the mechanism of oil displacement. The experimental results showed that, compared with nano-polymer microsphere flooding, the composite system of low salinity water and nano-polymer microsphere increased the recovery rate from 17.8% to 24.4%. The subsequent waterflooding stabilization injection pressure increased from 1.40 MPa to 2.43 MPa, and the corresponding plugging efficiency increased from 49.3% to 67.9%. The NMR study indicated that, in the polymer microsphere drive stage, the produced oil mainly came from the large pore spaces, accounting for 75% on average. With a lower solution salinity, the percentage of crude oil produced from the medium pore space to the total oil produced in the microsphere drive stage increased from 15% to 23%. The lower the salinity, the higher the oil produced from small- and medium-sized pores. Our results showed that polymer microspheres eliminated water channeling and changed flow direction, forcing the low-salinity water to enter smaller pores and improving the sweep and oil displacement efficiency. This study confirms the potential of synergistic flooding with low salinity water and nano-polymer microspheres in enhancing oil recovery in low permeability reservoirs. This study is the first to visually assess the impacts of nano-polymer- assisted low-salinity water flooding using NMR online tests. We confirmed that this combined technology successfully achieved both profile control and oil displacement. The nano-polymer-assisted low-salinity water flooding holds the advantages of low cost and simple construction, implying great potential in low permeability reservoirs.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Summary If hydrogen is stored in depleted gas fields, the remaining hydrocarbon gas can be used as cushion gas. The composition of the backproduced gas depends on the magnitude of mixing between the hydrocarbon gas and the hydrogen injected. One important parameter that contributes to this process of mixing is molecular diffusion. Although diffusion models are incorporated in the latest commercial reservoir simulators, effective diffusion coefficients for specific rock types, pressures, temperatures, and gas compositions are not available in the literature. Thus, laboratory measurements were performed to improve storage performance predictions for an underground hydrogen storage (UHS) project in Austria. An experimental setup was developed that enables measurements of effective multicomponent gas diffusion coefficients. Gas concentrations are detected using infrared light spectroscopy, which eliminates the necessity of gas sampling. To test the accuracy of the apparatus, binary diffusion coefficients were determined using different gases and at multiple pressures and temperatures. Effective diffusion coefficients were then determined for different rock types. Experiments were performed multiple times for quality control and to test reproducibility. The measured binary diffusion coefficients without porous media show a very good agreement with the published literature data and available correlations based on the kinetic gas theory (Chapman-Enskog, Fuller-Schettler-Giddings). Measurements of effective diffusion coefficients were performed for three different rock types that represent various facies in a UHS project in Austria. A correlation between static rock properties and effective diffusion coefficients was established and used as input to improve the numerical model of the UHS. This input is crucial for the simulation of backproduced gas composition and properties which are essential parameters for storage economics. In addition, the results show the impact of pressure on effective diffusion coefficients, which impacts UHS performance.
- Asia (0.93)
- Europe > Austria (0.68)
- North America > United States > Michigan (0.28)
- Geology > Rock Type (0.88)
- Geology > Geological Subdiscipline (0.66)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > Natural gas storage (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Investigation of Carbonate Matrix Damage and Remediation Methods for Preformed Particle Gel Conformance Control Treatments
Almakimi, Abdulaziz A. (Kuwait Institute for Scientific Research) | Liu, Junchen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Hussein, Ibnelwaleed A. (Missouri University of Science and Technology (Corresponding author))
Summary Preformed particle gels (PPGs) have been widely applied to control excessive water production in mature oil fields with fractures or fracture-like features, especially in sandstones, but with limited attention to carbonates. However, a vital concern arises regarding the potential damage of PPGs on the adjacent matrix that might promote negative results. This paper comprehensively evaluates PPGs’ potential damage to the carbonate matrix and seeks design optimization solutions. Filtration tests were applied to compare PPGs’ penetration into the matrix under different sets of conditions. The filtration regimes were defined by filtration curves, and the gel damage on the matrix was determined by permeability measurement results. Experiments were conducted to investigate the efficiency of an oxidizer as a remediation method to remove the damage. The qualitative description of gel particles’ invasion and plugging behavior in the carbonate matrix was presented based on the analysis of filtration test results and permeability measurements. The results show that the swollen gel filtration curves can be divided into three regions: prior-filter-cake, filter-cake-building, and stable stages according to the gel particles’ response to the injection pressure and effluent flow rates. PPGs can form cakes on the rock surface to prevent particles’ further penetration into the carbonate matrix, and the penetration was only limited to less than a few millimeters. The smallest gel particles (50–70 US mesh size) were more likely to form external and internal filter cakes at higher pressure values (700 psi) and result in more damage to the matrix. To restore the matrix permeability after filtration tests, oxidizer soaking proved to be a reliable solution. In all, the results indicated that unintentional matrix permeability damage induced by gel injection is generally unavoidable but conditionally treatable.
- Asia > Middle East (0.68)
- North America > United States > Oklahoma (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.66)
- Well Drilling > Formation Damage (1.00)
- Well Drilling > Drilling Fluids and Materials (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)