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The prediction of pH-dependent scales such as carbonates and sulfides presents unique challenges because their formation is strongly related to the three phase partitioning of the acid gases (CO2 and H2S). A rigorous procedure is required to ensure proper modelling of the hydrocarbon phases, in order to derive the correct data input for the software from available field data. Using this input, reliable scale prediction calculations may then be run using either integrated or separate PVT and scale prediction software. Although some carbonate scale prediction methods have been published in the past, these methods are field and software specific, and they do not provide a general procedure for carbonate and sulfide scale predictions in oil and gas wells. Operators also have in-house proprietary procedures, but these are not publicly available and hence cannot be used or critically reviewed by the wider upstream chemistry community.
This work presents an improved version of the original Heriot-Watt scale prediction workflow previously published in 2017 (
The workflow is built on three general calculation blocks which apply to all field scenarios, as follows: 1. defining a total PVT feed; 2. modelling the water chemistry leaving the reservoir; 3. running scale prediction calculations throughout the system. After describing the general carbonate and sulfide scale prediction procedure in details, this paper also looks into the specific calculation steps required in different scenarios for variable oil type, sample availability (topside vs downhole), software choice (integrated vs separate PVT and aqueous phase models), EOR, reservoir souring, artificial lift, and HP/HT/HS.
This is a truly general approach to carbonate and sulfide scale predictions which the authors hope will provide a widely available, useful tool to anyone performing field prediction studies for pH-dependent scales. In addition, a worked example is presented in
Formation water samples are often collected via formation testing from appraisal wells to aid scale management planning. It is important that the samples, and analyses obtained from them, are of good quality. The risk of obtaining poor quality samples/analyses is, in part, determined by the methods, procedures and equipment selected by the operator. To reduce this risk, it is useful to simulate the anticipated sampling conditions ahead of formation testing. This aids selection of optimum methods, procedures and equipment to obtain formation water samples/analyses for scale management planning given the constraints of the drilling and testing programmes.
To demonstrate the approach, scale prediction software has been used to simulate the conditions experienced by samples obtained from low, moderate and high pressure and temperature reservoirs (all non-H2S-bearing). A typical North Sea formation water composition was assumed but the composition was varied to explore how this affected the results. A wide range of sampling scenarios have been modelled. For example, these have looked at the effects of sampling drawdown, sampling below the bubble point, in the transition zone and below the OWC, use of different types of sample chambers, and use of different post-sampling handling methods.
The simulation results show, for given reservoir conditions and formation water compositions, why, and how, the compositions can be affected by the choice of sampling methods, procedures and equipment. This has allowed recommendations to be made with respect to how to produce water from the test zone, what type of sampling tools should be used under different circumstances, and how the samples should be handled after collection for each category of reservoir. The same approach can be used after acquisition to help confirm the quality of the samples/analyses obtained (i.e. by simulating the actual sampling conditions encountered).
How to estimate operational controls so as to optimize economic returns in CO2-WAG projects and reduce calcite scale risk? The reactivity and heterogeneity intrinsic to carbonate reservoirs make CO2-WAG (Water Alternating Gas) injection a big challenge. While miscibility effects greatly increase oil recovered, the presence of CO2 can cause severe flow assurance issues. The aim of this paper is to introduce a simulation-based methodology to optimize the design of CO2-EOR operations, considering economics, mineral scaling risk and environmental impact.
A compositional reservoir model was built to simulate a reactive 3-phase miscible flow in porous media. Aiming at maximizing the Net Present Value (NPV), we optimized the following operational variables: duration of waterflooding period; injection rates; producer bottomhole pressure (BHP); WAG ratio, gas half-cycle duration and number of cycles for different WAG stages (tapered WAG). We then used the forecasted data to quantify calcium carbonate scaling tendency for the scenarios of interest and design scale management strategies (squeeze treatments) with the lowest costs.
The optimal WAG design found through the methodology increased NPV by 55.6% compared to a base-case waterflooding scenario. We also found that performing a waterflood in a carbonate reservoir with high CO2 content will result in more severe calcite scale risk than applying equivalent WAG schemes. A lower production BHP can reduce the potential for precipitation, by allowing the CO2 to evolve from the aqueous solution within the reservoir, before it arrives at the production wellbore. On the other hand, a lower producer BHP can increase water production rates and, therefore, scale risk.
The proposed workflow provides valuable insights on the procedures involved in simulating and optimizing CO2-WAG projects with high calcite scale risk. Its application demonstrated the importance of an integrated analysis that seeks for higher economic returns in a sustainable manner, with reduced production issues caused by CO2 speciation.
Fakher, Sherif (Missouri University of Science and Technology) | El-Tonbary, Ahmed (American University) | Abdelaal, Hesham (University of Lisbon) | Elgahawy, Youssef (University of Calgary) | Imqam, Abdulmohsin (Missouri University of Science and Technology)
Carbon dioxide (CO2) is the main greenhouse gas contributing to environmental damage and global warming. It is emitted as a result of many processes, part of which is combustion of oil and gas. One of the methods by which CO2 emissions can be controlled or reduced is through CO2 sequestration processes. This research investigates the ability to store CO2 in shale reservoirs through adsorption and some of the factors impacting the adsorption capacity. CO2 adsorption was measured using the volumetric adsorption method using pulverized shale particles of uniform size. Initially, the void space in the shale-bearing cell was measured using helium. The void space is used in the CO2 adsorption calculations in order to account for the extra volume created when the shale core was pulverized. The effect of varying the CO2 pressure, temperature, and shale volume on the CO2 adsorption capacity was studied. Results showed that both pressure and temperature had a strong effect of CO2 adsorption, with an increase in pressure resulting in an increase in adsorption and an increase in temperature resulting in a decrease in adsorption. Altering the volume of the shale resulted in a change in adsorption as well due to an increase in error as the shale volume decreased relative to the vessel volume. This research provides insight on the impact of multiple factors on CO2 adsorption to shale particles thus illustrating the potential for CO2 storage in unconventional shale reservoirs.
Zhang, Xuan (China University of Petroleum East China) | Zhang, Guicai (China University of Petroleum East China) | Ge, Jijiang (China University of Petroleum East China) | Wang, Yanqing (The University of Tulsa)
Foam could increase the apparent viscosity of carbon dioxide (CO 2) significantly and control the mobility. This work focused on the enhancement of CO 2 foam stability with adding modified silica nanoparticles, which effected by the concentration ratio, pH and salinity. The results demonstrated that the interaction between the nanoparticles and surfactants was effected by both salinity and pH, and the mixing solution of 0.5 wt% NPs and 0.2 wt% C1202 was colloidal stable in high salinity brine at pH4.5 and 80 C, while at high pH 6.5, the NPs will aggregate. Higher nanoparticles concentration with constant surfactant concentration would increase the solution colloidal stability due to lower density of surfactant adsorbing at nanoparticles surface. The interfacial tension between CO 2 and water dropped to around 6mN/m significantly with surfactant C1202 and adding nanoparticles has slight effect on interfacial tension. However, the compression modulus increased maximum 3 times obviously calculated by the decrease of interfacial tension in shrinking process, which proved that due to strong and irreversible nanoparticles adsorption. Moreover, the core flooding results confirmed that adding NPs results in more viscous foam generation to reduce the CO 2 mobility and the total oil recovery enhanced 17% comparing with water flooding. This mixing solution makes it possible to enhance CO 2 foam stability at low pH and given high salinity, which is important to reduce gas mobility in reservoir conditions and, eventually, enhance oil recovery.
Fauziah, Cut Aja (Curtin University) | Al-Khdheeawi, Emad A. (Curtin University) | Iglauer, Stefan (University of Technology-Petroleum Technology Department) | Barifcani, Ahmed (Edith Cowan University)
Wettability of CO2–water– reservoir rock system is a key factor to determine fluid dynamic and storage capacities in CO2 geo-storage process. Despite the past researches on this matter, the parameters that influence the CO2–water–rock wettability variation are still not fully understood. One of these parameters is rock-total organic content (TOC). Thus, here, we investigated the effect of TOC on the CO2–water–sandstone wettability and the implication for CO2 geo-storage at relevant reservoir conditions. The used sandstone samples were retrieved from the South West Hub CO2 capture and storage project (GSWA Harvey 1) in Western Australia. Here, we measured the contact angles for a range of sandstone TOC (i.e. 0.01 wt %, 0.015 wt %, 0.017 wt %, and 0.019 wt % TOC) at various pressures (5 MPa, 10 MPa, 15 MPa, and 20 MPa) and at an isothermal reservoir temperature (334 K). The results indicate that both of the advancing (
Two global challenges are an increase in carbon dioxide (CO2) concentration in the atmosphere, causing global warming and an increase in energy demand (
In this study, a depleted sandstone reservoir located in the Norwegian Continental Shelf (NCS) is used. An innovative development scenario is considered, involving two phases: CO2 storage phase at the beginning of the project followed by a CO2-EOR phase. The objective of this paper is to evaluate the effect of different injection methods, including continuous gas injection (CGI), continuous water injection (CWI), Water Alternating Gas (WAG), Tapered WAG (TWAG), Simultaneous Water Above Gas Co-injection (SWGCO), Simultaneous Water and Gas Injection (SWGI) and cyclic SWGI on oil recovery and CO2 storage potential in the depleted reservoir.
A conceptual 2D high-resolution heterogeneous model with one pair injector-producer is used to investigate the mechanisms taking place in the reservoir during different injection methods. This knowledge is applied in a field scale, realistic 3D compositional reservoir model of a depleted sandstone reservoir in the NCS including ten oil producers and twenty water/gas injectors.
The simulation results demonstrate that innovative development scenario is viable to improve oil recovery and storage capacity in the depleted reservoirs. Different injection scenarios are benchmarked, and cyclic SWGI method is found to be the most efficient scenario in enhancing oil recovery and employing the highest capacity for CO2 storage.
This study shows the application of scaling analysis in the context of CO2 storage. Scaling analysis has been used in many flooding processes to characterize the displacement in such systems. The study aims to derive the key dimensionless numbers pertinent to CO2 storage in saline aquifers. This set of dimensionless numbers may be used to characterize important storage characteristics such as injectivity, plume migration and mobility, the pressure response and the ultimate storage capacity in potential saline aquifers.
CO2 storage in a two-dimensional cross-sectional model representing part of a saline aquifer was considered. The model is assumed to be full of brine when CO2 is injected into it. The fundamental equations for the material conservation of each phase, and the transport equations were formulated and derived. All fluids and the formation were considered compressible. These fundamental equations were then converted into the dimensionless domain by applying inspectional analysis to allow the identification of the key dimensionless numbers characterizing the storage process.
The storage process in such a system can be described by twelve dimensionless numbers, each of which characterize a different aspect of the storage process. Some numbers are similar to those already observed in the context of petroleum processes while a few of them are solely relevant to the storage process. Importantly, the pressure response and the injectivity consideration of the storage process can be described by the injectivity number and the ratio of compressibilities.
A numerical model was constructed to test the sensitivity of the storage process with respect to these dimensionless numbers. Results show the same set of dimensionless numbers can describe storage performance in different systems as long as the processes in all of them are described by identical dimensionless numbers. The lateral migration of the plume and its onset arrival at the storage boundary can be described by the combination of the magnitudes of gravity numbers, effective aspect ratio number, mobility ratio between CO2 and brine and finally the ratio of CO2 and formation compressibilities relative to brine compressibility.
For a confined storage system, the storage efficiency was correlated with the magnitudes of the influencing dimensionless numbers. The derived dimensionless numbers may be used as a set of characterization parameters for describing the storage process in potential storage candidates. They can also be used effectively as a preliminary screening criteria for the purpose of site selection amongst potential storage candidates.
Fakher, Sherif (Missouri University of Science and Technology) | El-Tonbary, Ahmed (American University in Cairo) | Abdelaal, Hesham (University of Lisbon) | Elgahawy, Youssef (University of Calgary) | Imqam, Abdulmohsin (Missouri University of Science and Technology)
Unconventional shale reservoirs have become and large unconventional supplier of oil and gas especially in North America. They are usually produced from using hydraulic fracturing which produces and average of 7-10% per well. This research studies the application of carbon dioxide (CO2) enhanced oil recovery (EOR) in shale reservoirs to increase oil recovery to more than 20%. Cyclic CO2 injection was used to conduct all experiments rather than flooding. The main difference between both procedures and the advantage of cyclic injection over flooding in shale reservoirs is explained. A specially designed vessel was constructed and used to mimic the cyclic CO2 injection procedure. The effect of CO2 soaking pressure, CO2 soaking time, and number of soaking cycles on oil recovery was investigated. Results showed that cyclic CO2 injection can increase oil recovery substantially, however there are some points that must be taken into consideration including optimum soaking pressure and time in order to avoid a waste of time and capital with no significant increase in oil recovery. This research not only provides an experimentally backed conclusion on the ability of cyclic CO2 injection to increase oil recovery from shale reservoirs, it also points to some major issue that should be considered when applying this EOR method in unconventional shale in order to optimize the overall procedure.
Edem, Donatus (University of Salford, Manchester, United Kingdom.) | Abba, Muhammad (University of Salford, Manchester, United Kingdom.) | Nourian, Amir (University of Salford, Manchester, United Kingdom.) | Babaie, Meisam (University of Salford, Manchester, United Kingdom.) | Naeem, Zainab (University of Salford, Manchester, United Kingdom.)
A laboratory investigation was carried out to experimentally determine the extent of the salt precipitation effects on the petrophysical properties of deep saline aquifer during CO2 storage. This was performed on selected core samples using laboratory core flooding process. The petrophysical properties (Porosity, Permeability) of the core sample were measured before core flooding using Helium Porosimetry and Scanning Electron Microscopy (SEM) to determine the morphology of the core samples. The core samples were saturated with brines of different salinities (5, 15, 25, wt% NaCl) and core flooding process was conducted at a simulated reservoir pressure of 1,000 psig, temperature of 45°C, with varying injection rates of 1.0, 1.5, 2.0, 2.5 and 3.0 ml/min respectively. The obtained results indicated that the porosity and permeability decreased drastically as salinities increases, noticeably because the higher concentration of brine resulted in higher amounts of salt precipitation. Porosity reduction ranged between 0.75% to 6% with increasing brine salinity while permeability impairment ranged from 10% to 70% of the original permeability. The SEM images of the core samples after the flooding showed that salt precipitation not only plugged the pore spaces of the core matrix but also showed significant precipitation around the rock grains thereby showing an aggregation of the salts. This clearly proved that the reduction in the capacity of the rock is associated with salt precipitation in the pore spaces as well as the pore throats. Higher injection rates induced higher salt precipitation which caused reduction in porosity and permeability. This is attributed to the fact that; the higher injection of CO2 vaporizes the formation brine more significantly and thereby increasing brine concentration by removing the water content and enhancing precipitation of salt. These findings provide meaningful understanding and evaluation of the extent of salt precipitation on CO2 injectivity in saline reservoirs. The insight gained could be useful in simulation models to design better injectivity scenarios and mitigation techniques