The objectives of the present study are to evaluate a zwitterionic surfactant for applicability in EOR. The surfactant was tested in terms of its salt tolerance, thermal stability, interfacial reduction capability, wettability alteration and resistance to adsorption. The effect of salinity and alkalinity was also tested on the above stated physico-chemical properties of the surfactant.
The salt tolerance of the surfactant was tested by testing for precipitation of surfactant solution with increasing salinity at 30 °C and 80 °C. The thermal stability of the surfactant was tested by TGA testing. The interfacial tension of the crude oil and surfactant solution with varying surfactant concentration, salinity and alkalinity was tested by spinning drop technique. The wettability alteration by surfactant solution was tested by measuring contact angle on an oil wet sample. The adsorption study was done by measuring the concentration of surfactant after its solution was exposed to adsorption on crushed rock sample.
The surfactant had salt tolerance of 20% salinity. The surfactant was found stable to 130 °C as per TGA curve. The interfacial tension (IFT) was reduced to ultralow value by surfactant solution for concentration at and above its critical micelle concentration. The presence of salt had minimal effect on the IFT reduction capability of the surfactant solution. Presence of alkali had synergetic effect on IFT reduction. The wettability of the oil wet sample was altered to preferentially water wet by surfactant. The loss of surfactant due to adsorption was found to be within recommenced range for applicability in EOR. These excellent physico-chemical properties of the zwitterionic surfactant suggest that it can be used in the mature oil fields for recovery of trapped oil.
This paper presents design, testing, installation, and lessons learned with the world's first completely integrated managed pressure drilling (MPD) control system on a deepwater drilling rig. While previous MPD installations have included driller-operated systems, they all include additional human machine interfaces (HMI) and standalone control network components with limited use of rig data and limited to no interfaces to other critical drilling machines on the drilling rig. For the installation described in this paper, all MPD control functions were permanently installed on the main drilling control network of the drilling unit, providing direct access to high speed data from other drilling machines that influence the wellbore pressure. This includes the rig's mud pumps, top drive, and drawworks. Moreover, the MPD control system has the ability to actively control the drilling machines, thereby optimizing performance through coordinated control of mud pump, top drive, and MPD chokes during drilling and connections.
Cement sheath is a critical barrier for maintaining well integrity. Formation of micro-annulus due to volume shrinkage and/or pressure/temperature changes is the major challenge in achieving good hydraulic seal. Expansion of cement after the placement is a promising solution to this problem. Expanding cement can potentially close micro-annulus and further achieve pre-stress condition because of the confinement. Primary aim of this paper is to investigate mechanical integrity of different pre-stressed cement system under loading condition.
To achieve the objectives, finite element modelling approach was employed. Three dimensional computer models consisting of liner, cement sheath, and casing were developed. Pre-stress condition was generated by modelling contact interference at the cement-casing interface. Three cement (ductile, moderately ductile, and brittle) were considered for simulation cases. Wellbore and annulus pressure were applied. Resultant, radial, hoop, and maximum shear stresses were investigated at the cement-pipe interface to assess mechanical integrity. For comparison purpose, similar simulations were conducted using cement sheath without pre-stress and cement system representing uniform volume shrinkage and presence micro-annulus.
For constant wellbore pressure, the radial stresses observed in all three types of cement system were practically similar and decreased as pre-stress was increased. Hoop stress also reduced with increase in compressive pre-load. However, their absolute values were distinct for different cement types. These results indicate that cement system with compressive pre-load can notably reduce the risk of radial crack failure by providing compensatory compressive stress. However, on the contrary, the maximum shear stress developed at cement-pipe interface, increased because of pre-load. This can compromise the mechanical integrity by reducing the safety margin on shear failure. Thus, the selection of expansive cement should be made after carefully weighing reduced risk of radial failure/debonding against the increased risks of shear failure.
This paper provides novel information on expanding cement from the perspective of mechanical stresses and integrity. Modelling approach discussed in this work, can be used to estimate amount of pre-stress required for a selected cement system under anticipated wellbore loads.
Wu, Xiaye (The University of Oklahoma) | Han, Lihong (Tubular Goods Research Institute of CNPC) | Yang, Shangyu (Tubular Goods Research Institute of CNPC) | Yin, Fei (Chengdu University of Technology) | Teodoriu, Catalin (The University of Oklahoma) | Wu, Xingru (The University of Oklahoma)
Due to the layered texture and sedimentation environment, shale formations usually characterized as high heterogeneity and anisotropy in in-situ stresses. During the hydraulic fracturing process, fracturing fluid is injected at a pressure above the formation pressure. This injection process changes the local in-situ stresses in a quick and significant manner while generating fracture systems. In the regions of existing geo-features such as natural fractures and faults, local stress changes could lead to the activation of formation movement, which in return impacts the casing going through the locale. Casing deformations during hydraulic fracturing have been observed in Southwest China Sichuan basin, and it have impeded completion operations in certain regions. In order to ensure further exploring, we analyszed this phenomenon and propose practical solutions for fault reactivation prevention.
To study the mechanism of local slippage and the impact on casing integrity, we set up a 2D finite element model with considerations of in-situ stresses acquired from fields, natural fracture orientation from available seismic data, and we simulated water injection process in order to quantify potential slippage and displacement. The finite element model features an integration of casing, cementing, and formation under the hydraulic fracturing conditions. For particular parameters such as permeability and leak-off coefficeint, we conducted sensitivity studies to quantify their impacts on displacement amount.
The theoretical geomechanics studies indicate water induced slippage existence in shale due to its fracture reactivation. Using the finite element model, this paper interpreted and quantified the impact of fracturing fluid injection on casing from strike-slip fault regiems. Simulation results revealed that water injection into natural fractured shale formation can induce finite displacement characterized as fault slippage along discontinues surfaces. This study could help engineers to have a better prediction as how hydraulic fracture intereact with subsurface structures and potential risks that comes along with it. This type of casing damage can be reduced by improving well trajectory design, completion operation, and higher strength level of casing-cement system.
The findings from this study not only can be applied to naturally fractured formations, but also to other pre-existing geo-features such as discountinues surfaces. It also provides fundamental basis for more practical solution to find the measures and overcome the casing deformation problems in hydraulic fracturing.
Thomas, Sunil (Chevron Energy Technology Company) | Du, Song (Chevron Energy Technology Company) | Dufour, Gaelle (Chevron Energy Technology Company) | Mallison, Brad (Chevron Energy Technology Company) | Muron, Pierre (Chevron Energy Technology Company) | Rey, Alvaro (Chevron Energy Technology Company)
New developments in unstructured aggregation-based upscaling are presented that improve the flexibility of coarsening designs and enable a more integrated reservoir simulation workflow. Field cases and synthetic tests demonstrate the advantages of the method compared to legacy upscaling methods and fine scale simulations.
Aggregation-based upscaling has recently emerged as a favorable alternative to conventional upscaling methods in reservoir simulation workflows. We outline these developments and describe algorithms used to compute flexible aggregation schemes, coarse transmissibility, and upscaled well indices. The main value additions are,
the ability to selectively coarsen and adapt areal and vertical resolution based on geological features, areas of interest, and/or stratigraphic layer metrics resulting in improved accuracy, the improved simplicity and robustness resulting from avoiding the explicit creation of coarse grids and maintaining one grid for earth modeling and reservoir simulation workflows, and the broad applicability to fields modeled by many grid types including unstructured grids and discrete fracture models.
the ability to selectively coarsen and adapt areal and vertical resolution based on geological features, areas of interest, and/or stratigraphic layer metrics resulting in improved accuracy,
the improved simplicity and robustness resulting from avoiding the explicit creation of coarse grids and maintaining one grid for earth modeling and reservoir simulation workflows, and
the broad applicability to fields modeled by many grid types including unstructured grids and discrete fracture models.
The aggregation-based upscaling methodology is tested in the simulation of some synthetic benchmarks, and of full field models. Comparisons are provided to fine scale simulations in each case, and to legacy upscaling simulations, wherever practically feasible. The most important findings are the seamless integration afforded by the new workflow by eliminating the need for the coarse simulation grid, the significant savings in user interaction time and computational time, and the overall improvement in accuracy, when compared to legacy upscaling workflows. This is important because reservoir engineers operate on tight deadlines to complete projects, and because the logistical challenges of handling fine and coarse grids are significant for studies that involve multiple reservoir model realizations.
Abdelfatah, Elsayed (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary) | Chen, Yining (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary) | Berton, Paula (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary) | Rogers, Robin D (525 Solutions, Inc.) | Bryant, Steven (Canada Excellence Research Chair in Material Engineering for Unconventional Oil Reservoirs, Chemical and Petroleum Engineering Department, University of Calgary)
Thermal and flotation processes are widely used to produce bitumen from oil sand in Alberta. However, bitumen contains many surface-active components that tend to form water-in-oil emulsion stabilized by fines and/or asphaltenes. Although several demulsifiers have been proposed in the literature to treat such emulsions, these chemicals are sometimes not effective. We propose ionic liquids whose composition has been designed to enable effective treatment of these emulsions.
Different ionic liquids were synthesized and tested for their efficiency in treating bitumen emulsion obtained from a field in Alberta. Ionic liquids tested are mixtures of organic bases with acids. Mixtures of ionic liquids and bitumen emulsion were prepared at several mass ratios. The two components were mixed under ambient conditions. After mixing, segregation of different components in the mixture was accelerated by centrifugation for rapid assessment of the degree of emulsion breaking. Optical microscopy, rheology, thermal gravimetric analysis, and viscosity measurements were used to assess the effect of ionic liquids on bitumen emulsions.
The first set of ionic liquids with cations of different alkyl chain lengths were able to separate the water from the emulsion. However, these ionic liquids tend to form a gel when mixed with water. The number and length of alkyl chains proved critical for avoiding gel formation. Ionic liquids with multiple long chains on the cation were immiscible with the separated water. These ionic liquids were very efficient in diluting and demulsifying bitumen emulsion. The emulsion droplet sizes increased upon addition of the ionic liquid. The ionic liquid mixes into the bitumen phase released from the emulsion, yielding a viscosity at ambient temperature close to the pipeline specifications.
This work demonstrates that ionic liquids can be tailored to break bitumen emulsions effectively without heat input. The process developed in this paper can replace current practice for the demulsification and dilution of bitumen emulsions, which requires the emulsion to be heated significantly. Hence the ionic liquid process reduces the heat requirements and hence greenhouse gas emissions.
We suggest two new thermodynamic models for the adsorption of ions to the brine/carbonate and brine/crude oil interface. We calibrate the model parameters to the ionic adsorption and zeta potential data. We then investigate the effect of the rock and oil surface charges on the dissolution, wettability alteration, and mechanical properties of the carbonates in the context of modified-salinity water flooding in the North Sea chalk reservoirs.
We modify a charge-distribution multi-site complexation (CD-MUSIC) model and optimize its parameters by fitting the model to a large data set of calcite surface zeta potential in presence of different brine compositions. We also modify and optimize a diffuse layer model for the oil/brine interface. We then use the optimized surface complexation models with a finite-volume solver to model the two phase reactive transport of oil and brine in a chalk reservoir, including the impact of dissolution, polar-group adsorption, and compaction on the relative permeability of chalk to water and oil. We compare the simulation results with the published experimental data.
Zhao, Tianhong (Southwest Petroleum University) | Chen, Ying (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Wei, Bing (Southwest Petroleum University) | He, Yi (Southwest Petroleum University) | Zhang, Yiwen (Southwest Petroleum University)
Nanofluid flooding injection technique whereby nanomaterial or nanocomposite fluids for enhanced oil recovery (EOR) have garnered attention. Although a variety of nanomaterials have been used as EOR agents, there are still some defects such as toxicity, high cost and low-efficiency displacement, which restricted the further application of these nanoparticles. Considering these problems mentioned above, it is necessary to search for another nanomaterial which is inexpensive, environmentally friendly and results in high efficiency displacement.
In this work, a natural aluminosilicate nanomaterial halloysite nanotubes (HNTs) was focused. As a new kind of nanomaterial, the effectiveness of halloysite nanotubes (HNTs) in enhancing oil recovery has not been reported yet and it is still in its infancy. The use of pristine halloysite nanotube is at risk of blocking the rock pore channel due to the intrinsic drawback of aggregation, which may be the reason. To prolong the suspension time of fluids during seeping into the small pores of low permeable reservoirs, we have proposed the HNTs/SiO2 nanocomposites. The effect of HNTs/SiO2 nanocomposites-based nanofluids on wettability alteration and oil displacement efficiency was experimentally studied. The HNTs/SiO2 nanocomposites have been prepared by sol-gel method and characterized with X-ray (XRD), Transmission Electron Microscopy (TEM) and Thermal Gravimetric Analysis (TGA). The effect of the chemical modification on the suspension stability was investigated by measuring Zeta potential and dynamic laser scattering. Results show that the HNTs/SiO2 nanofluid could significantly change the water wettability from oil-wet to water-wet condition and enhance oil production. The optimal concentration of HNTs/SiO2 was 500 ppm, which corresponded to the highest ultimate oil recovery of 39%.
Hou, Qingfeng (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Zheng, Xiaobo (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Guo, Donghong (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Zhu, Youyi (Key Laboratory of EOR, Research Institute of Petroleum Exploration and Development, CNPC) | Yang, Hui (Key Laboratory of Colloid, Interface and Chemical Thermodynamics, Institute of Chemistry, Chinese Academy of Sciences) | Xu, Xingguang (Energy Business Unit, Commonwealth Scientific Industrial Research Organization) | Wang, Yuanyuan (Key Laboratory of Oilfield Chemistry, Research Institute of Petroleum Exploration and Development, CNPC) | Chen, Gang (Key Laboratory of Colloid, Interface and Chemical Thermodynamics, Institute of Chemistry, Chinese Academy of Sciences) | Hu, Guangxin (Key Laboratory of Colloid, Interface and Chemical Thermodynamics, Institute of Chemistry, Chinese Academy of Sciences) | Wang, Jinben (Key Laboratory of Colloid, Interface and Chemical Thermodynamics, Institute of Chemistry, Chinese Academy of Sciences)
Stimuli-responsive emulsions have attracted much attention in diverse fields. However, research on the rapid and effective demulsification based on pH-responsive emulsions has barely been reported, although they are viewed as promising canditates for oil-water separation processes after oil recovery. In the present work, we have successfully synthesized a series of pH-responsive emulsions on the basis of a novel polymer containing amphiphilic and protonated moieties. The properties of these pH-responsive emulsions including stability, morphology microscopy, Zeta potential, and interfacial tension have been extensively investigated. We observed that the prepared oil-in-water emulsion could stay stable for more than 24 h within the pH range of 8-10, while it lost 80-90% of the water in 10-20 min if the pH was adjusted to 2-4. The variation in emulsion stability can be attributed to the protonation of poly [2-(N, N-diethylamino) ethyl methacrylate] (PDEA) residues at low pH values. Accordingly the polymers intend to become more hydrophilic and depart from the oil-water interface, leading to an increased interfacial tension. Furthermore, it was found that the applied polymers aggregated at the oil-water interface and that the morphology of aggregations was strongly affected by the pH values. These proposed polymers enabled the formation of emulsion with a controllable response to the pH stimuli. This work is expected to shed light on the development of stimuli-responsive emulsions and may have significant implications in the fields of oil recovery, waste water treatment, and so forth. For example, due to the high w/o interface activity of surfactants such as heavy alkyl benzene sulfonate (HABS) and petroleum sulfonate, severe emulsion has also been found with the alkali-surfactant-polymer (ASP) produced fluid. Currently, rapid breaking of these emulsion fluid is still a big challenge.
We present a new fully-implicit, hybrid-mixed, mimetic finite difference (HMFD) discretization scheme for general-purpose compositional reservoir simulation. The locally conservative scheme solves the coupled momentum and mass balance equations simultaneously, and the fluid system is modeled using a cubic equation-of-state. We compare the method to other discretization schemes for unstructured meshes and tensor permeability. Finally, we illustrate the applicability and robustness of the method for highly heterogeneous reservoirs with unstructured grids.