Briefly stated, carbon capture and sequestration (CCS) will help us to sustain many of the benefits of using hydrocarbons to generate energy as we move into a carbon-constrained world. Even though the CO2 generated by burning hydrocarbons cannot always be captured easily in some cases (as in oil used for transportation), sequestration of CO2 from other sources (such as coal-fired power stations) can help to create, to some degree, the “headroom” needed for the volumes of CO2 that escape capture. Because of the likely continuing competitive (direct) cost of hydrocarbons and in light of the huge investment in infrastructure already made to deliver them, the combination of fossil fuel use with CCS is likely to be emphasized as a strong complement to strategies involving alternative, nonhydrocarbon sources of energy. Moreover, the exploitation of heavy oil, tar sands, oil shales, and liquids derived from coal for transportation fuel is likely to increase, even though these come with a significantly heavier burden of CO2 than that associated with conventional oil and gas. CCS has the potential to mitigate some of this extra CO2 burden. If we wish to sustain the use of oil, gas, and coal to meet energy demands in a carbon-constrained world and to provide time to move toward alternative energy sources, then it will be necessary to plan for and implement CCS over the coming decades. Subsequently, we should expect a continued need for CCS beyond the end of the century.
Carbon Capture and Sequestration (CCS) is a geologic and engineering enterprise designed to reduce atmospheric emissions of greenhouse gases (GHGs). Extensive research links the GHG concentration in the atmosphere to the observed change in global temperature patterns (IPCC, 2013; Cox et al., 2000; Parmesean and Yohe, 2003). CCS technology could play an important role in efforts to limit the global average temperature rise to below 2°C, by removing carbon dioxide originating from fossil fuel use in power generation and industrial plants.
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
Franklin M. Orr Jr., Stanford University Summary Recent progress in carbon capture, utilization, and storage (CCUS) is reviewed. Considerable experience has now been built up in enhanced-oil-recovery (EOR) operations, which have been under way since the 1970s. Storage in deep saline aquifers has also been achieved at scale. Introduction The challenge of making deep reductions in greenhouse gas (GHG) emissions in this century is a daunting one given the scale of the use of energy by humans and our current dependence on fossil fuels, which provide essential energy services at low cost to modern societies. Meeting the challenge of reducing GHG emissions will require a fully diversified portfolio of approaches, such as much more energy-efficient end-use technologies (e.g., cars, home and business heating and air conditioning, lighting); electrification of energy services coupled with reduced GHG emissions from electric power generation; fuel switching in transportation and electric power generation; deployment of additional renewable power generation; land-use changes toward lower-emission agriculture; emission reductions of short-term forcers such as black carbon, CH Integrated assessments of the various pathways indicate that portfolios that include significant deployment of CCUS have lower estimated costs than those without CCUS (Clarke et al. 2014; Krey et al. 2014). In 2005, the Intergovernmental Panel on Climate Change (IPCC) issued a detailed special report (SRCCS) on many aspects of carbon capture and storage (CCS) (Metz et al. 2005). Wilcox (2012) provided detailed descriptions of specific capture technologies and their energy requirements, as did Boot-Handford et al. (2014), who gave additional commentary on pipeline transportation issues, subsurface storage issues, and a European policy perspective.
With an increasing focus on identifying cost-effective solutions to well design with a minimal impact on productivity, this paper will focus on an alternative to cesium (Cs) formate as the perforation fluid in the high-pressure/high-temperature (HP/HT) Gudrun Field operated by Equinor. Cs formate has been used with success for drilling and perforating many HP/HT wells. However, because of the significant cost of this fluid coupled with low oil prices, Equinor wanted to perform testing to assess the performance of an alternative oil-based mud (OBM) as a perforation fluid. In this paper we describe the extensive qualification testing that we have conducted, which includes coreflooding using representative plugs from Gudrun Field under downhole temperature and pressure conditions. In addition, eight API RP19B (2014) Section IV perforation tests have been conducted to compare the performance of the Cs formate with the OBM. These tests were undertaken using gas- and oil-saturated cores to reflect different production scenarios. The main aspects of the perforation operation that were reflected in the test design were as follows:
On the basis of the results of the coreflooding combined with the API RP19B (2014) Section IV testing, the OBM was selected as the perforating fluid for use on Gudrun Field. The perceived benefits of using the OBM were as follows:
Perforation modeling is described, and a comparison is made between this and the API RP19B (2014) Section IV tests. Finally, the well-startup experiences and the production data are presented, demonstrating the effectiveness of the OBM as a perforation fluid.
Hattori, Koki (Tohoku University) | Watanabe, Noriaki (Tohoku University) | Okamoto, Atsushi (Tohoku University) | Nakamura, Kengo (Tohoku University) | Komai, Takeshi (Tohoku University) | Tamagawa, Tetsuya (Japan Petroleum Exploration Co., Ltd.)
In CO2 geological storage, CO2/brine/rock chemical interactions may lead to changes in mechanical properties of rocks. These changes can have impacts on performance and integrity in storage depending on their intensities. In case of sandstones consisting mainly of quartz and feldspar grains, there may be little changes in the properties because of low reactivities of the minerals. On the other hand, significant changes may occur in case of volcanic sandstones because they contain high-reactivity volcanic glasses. However, influences of the chemical interactions on the properties of volcanic sandstones have not been investigated so far. Thus, we have conducted triaxial compression experiments on two cylindrical volcanic sandstone samples consisting mainly of andesite/basalt and scoria grains (porosity: ca. 33%) at a confining/axial pressure of 30 MPa, pore pressure of 15 MPa, CO2 saturation of 50% or 77% and 60°C for several weeks. Bulk modulus, Young’s modulus and Poisson’s ratio were measured intermittently. Before and after the experiment, porosity and permeability were also measured on each sample, and initial and final brine chemistries were analyzed. Additionally, X-ray CT was conducted on the samples before and after the experiment. Changes in bulk modulus and Young’s modulus were qualitatively similar whereas Poisson’s ratio was almost constant. In case of one of the sample that contained relatively large scoria grains of high porosities, bulk modulus first decreased, then recovered partially, and finally became constant. In case of the other sample, bulk modulus first increased and then became constant. The decrease and increase in bulk modulus may have been caused respectively by dissolution-induced collapse of the relatively large scoria grains and by precipitations of some minerals such as silica minerals. Permeability of one of the samples increased while permeability of the other sample decreased, although porosity decreased for both samples.
To solve the global warming problem, many countries have attempted to reduce CO2 emissions. CO2 capture and storage (CCS) utilizing reservoir rocks such as porous sandstones at depth is considered as one of promising ways to reduce CO2 emissions. Indeed, CCS demonstration tests have been conducted in various countries. A test has been conducted in Sleipner field (North Sea) since 1996 (Baklid et al., 1996), where CO2 injection has averaged almost 1 Mt per year with more than 16 Mt successfully stored by 2016 (White et al., 2017). A test has also been conducted in Tomakomai, Japan. The storage potential in Japan by the proposed scheme is evaluated to be 71.6 Gt, which corresponds to the emission in Japan for 53.6 years (Suekane et al., 2007).
Al Ramadhan, Abdullah (EXPEC Advanced Research Center, Saudi Aramco) | Hemyari, Emad (EXPEC Advanced Research Center, Saudi Aramco) | Bakulin, Andrey (EXPEC Advanced Research Center, Saudi Aramco) | Erickson, Kevin (EXPEC Advanced Research Center, Saudi Aramco) | Smith, Robert (EXPEC Advanced Research Center, Saudi Aramco) | Jervis, Michael A. (EXPEC Advanced Research Center, Saudi Aramco)
In 2015, Saudi Aramco started a CO2 Water-Alternating-Gas (WAG) EOR pilot project in an onshore carbonate reservoir. To monitor lateral expansion of the CO2 plume, the area was instrumented with a hybrid surface/downhole permanent seismic monitoring system. This system consists of over 1000 buried seismic sensors at a depth of around 70 m, below the the depth of expected weathering layer to mitigate the time-lapse noise. Despite receiver burial, seismic data still suffers from numerous challenges including: significant amounts of high-amplitude coherent noise such as guided waves, mode conversions, and scattered energy; amplitude variations over space and time caused by source and receiver coupling; variability of wavelet shape and arrival times due to seasonal near-surface variations; and low signal-to-noise ratio (SNR). A novel processing workflow was designed for 4D processing of such data. The workflow involves five critical processes. First, the high-amplitude coherent noise is eliminated using FK-based techniques that are 4D compliant to preserve the reservoir changes between repeated seismic surveys. Second, a four-term joint surface-consistent amplitude-scaling algorithm resolves the amplitude variations. The algorithm allows both source and receiver terms to have different scalars for the same positions, but it restricts the other two terms to be position-invariant over different time-lapse surveys, as the window of analysis does not include the reservoir. This is to guarantee that the source and receiver terms are survey-dependent while the other two terms are survey-independent. Thus, the amplitude variability is linked to source and receiver positions over space and time. It also assures that the reservoir changes are not affected by changes in the overburden. Third, wavelet shape variations are addressed using a four-term joint surface-consistent spiking deconvolution algorithm that applies similar principle as the scaling algorithm. Fourth, the small variations in reflection times between different surveys (4D statics) caused by seasonal variations are corrected by a specialized surface-consistent residual statics algorithm using a common pilot derived from the base survey. Fifth, the pre-stack data is supergrouped to enhance the signal-to-noise ratio and repeatability.
The processing workflow has been applied to frequent land 3D seismic data acquired over a CO2 WAG EOR pilot project in Saudi Arabia. As a result, we obtained very repeatable seismic images that may successfully detect small CO2-related changes in a stiff carbonate reservoir.
Carbon Capture and Storage (CCS) is indeed a very effective technology in reducing the CO2 concentrations from the atmosphere and possesses massive potential for mitigating climate change. Over the years CCS processes has evolved, however, it is still believed to be in initial phase and appears as a new idea to many under developed countries. Today CCS appears as the only applicable solution to reduce Gigatonnes (Gt) CO2 emissions besides burning the fossil fuels for energy. The application, however, is not as straightforward as it appears. The high costs and potential risks associated leaves the vision of mitigating climate change through CCS under obscurity, thereby, making the future of CCS a bit vague. This paper aims to project the near future of CCS by the analysis of present CCS prospects, CO2 capturing and storage processes, risks and problems associated, and more importantly the economics encompassing a CCS project. The paper begins with the brief overview of Carbon Capture and Storage (CCS), followed by a comparison of different capturing processes, storage mechanisms, potential problems and risk complications; a comparison of renewables in contrast with CCS is provided. Lastly, the economics and costs of present CCS prospects in different parts of world are discussed.
Hamdi, Zakaria (Universiti Teknologi PETRONA) | Awang, Mariyamni (Universiti Teknologi PETRONA) | Basyouni, Ahmad (Universiti Teknologi PETRONA) | Hematpour, Hamed (Universiti Teknologi PETRONA) | Bataee, Mahmood (Universiti Teknologi PETRONA)
Gas flooding methods have been used as successful tertiary recovery agents for decades. Recent studies suggested the effectiveness of using low temperature CO2 injection in high temperature reservoirs. With respect to current economic limitations, nitrogen and CO2 seems to be one of the most conventional ways to improve the oil recovery. The high temperature reservoirs may not be suitable for isothermal gas injections as they would suffer from gravity override of the gas, while low temperature injection could minimize the effect. The main goal of this study is to compare the low temperature injection of these two fluids in high temperature reservoirs aiming to improve the oil recovery.
To obtain a proper comparison between CO2 and nitrogen, several simulations have been constructed and performed. Thermal compositional runs seem to be the perfect candidate to achieve the goals of this study. The results suggest that with equal injection amount and duration of both fluids, liquid CO2 is a better candidate for improving oil recovery. Ultimate recoveries for CO2 and nitrogen injection at same initial conditions were recorded as 73% and 55%, respectively. The effectiveness of liquid CO2 for oil recovery was recorded as 1.52 barrels of oil for each barrel of injection, whereas a barrel of nitrogen recovered only an average of 0.65 barrel of oil. The viscosity reduction was more severe in liquid CO2, which suggests better mobility for the oil than in nitrogen injection. The CO2 breakthrough happened at an earlier time than nitrogen but due to much higher ultimate recovery, it can be overlooked. The overall conclusion suggests that low temperature CO2 injection can be considered a beneficial and promising method for enhancing oil recovery in high temperature reservoirs.
The capacity for the storage of carbon dioxide in saline aquifers remains enormous. Of all geological storage media, it provides the best storage capacity. In this study, the potential of the Shuaiba Formation, in the Falaha syncline, for geologic sequestration is assessed. A regional geo-model was built using seismic and well data (logs, cores) from the Falaha Syncline and nearby fields. The model was built to honor the heterogeneity and sequence stratigraphy of the Shuaiba carbonate platform using a five-order hierarchical conceptual model of the Shuaiba formation that merged sequence architecture and reservoir architecture together. This was achieved by honoring lithofacies, facies association packages and rock types in their corresponding depositional settings in the sequence framework. Dynamic simulations were then conducted on an upscaled geological model using a compositional reservoir simulator to determine its storage and flow capacity, plume migration pathways and to understand the physics of the fluid flow in the aquifer. Simulations are made to be conservative thus accounting for structural/stratigraphic, solubility (dissolution in resident brine) and residual trapping without accounting for the slower mineral trapping process. Detailed sensitivity studies were conducted during the simulations to understand the effect of well parameters, rock and fluid properties amongst others on the storage capacity in the aquifer. Simulation results indicate that significant volumes could be stored in the aquifer and could take a significant amount of time before the injected gas reaches the surrounding hydrocarbon producing fields. This study provides the first full field approach to characterize and to quantify the suitability of the identified aquifer for long term storage of carbon dioxide in the subsurface of UAE.