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AbstractPrincipal Component Analysis (PCA) was used to evaluate groundwater quality data acquired in the pre-injection and injection periods for the Illinois Basin – Decatur Project (IBDP), a large-scale carbon capture and storage (CCS) project located in Decatur, Illinois, USA. For the pre-injection and injection periods three principal components explained 76.6% and 80.0% of the total data variance, respectively. Analysis of the pre-injection data set determined that highly positive loadings for total dissolved solids, chloride, bromide, sodium, magnesium, potassium, and electrical conductance designated the first component (PC1) as the salinity factor. High loadings for calcium, iron, and sulfate in component two (PC2) represents an oxidation-reduction component. The third component (PC3) represents groundwater acidity because of highly positive loading of pH. For the injection data set the variables contributed to the first component are bromide, sodium, total dissolved solids, chloride, electrical conductance, potassium, sulfate, iron, and calcium. Sulfate, magnesium, and calcium contribute to the second component and pH to the third component and represent salinity, dissolution, and acidity of groundwater. The results of the PC analysis indicate that water-rock interactions are the primary mechanism governing groundwater quality during both periods. The results of this analysis indicate that CO2 injection activities have not impacted the quality of the shallow groundwater in the project area.

AbstractElectrochemical splitting of calcium carbonate (e.g., as contained in inexpensive and abund ant minerals such as limestone) is proposed as a novel method of forming hydroxide solutions that can absorb, neutralize, and store carbon dioxide from the air or from waste streams. CaCO3 is dissolved in the presence of the highly acidic anolyte of a saline water electrolysis cell, forming Ca(OH)2 and H2CO3 (or H2O and CO2). By maintaining a pH between 6 and 9 in the resulting solution, subsequent hydroxide reactions with CO2 primarily produce dissolved calcium bicarbonate, Ca(HCO3)2. Thus, for each mole of CaCO3 split, there can be a net capture of up to 1 mole of CO2. The resulting dissolved Ca(HCO3)2 can be diluted and stored in the ocean, or in reservoirs on land or underground. Net process cost is estimated to be <$100/tonne CO2 mitigated.Other potential co-benefits of the approach include: i) production of significantly carbon-negative H2 if renewable - or nuclear - derived electricity is used as the power source, ii) the option of locally producing electricity and freshwater via fuel cell oxidation of the H2, iii) direct neutralization of ongoing ocean acidification if the Ca(OH)2 generated is added to seawater, iv) preservation or enhancement of otherwise threatened marine shellfish and coral populations, via CO2 absorption and Ca(HCO3)2 formation in or addition to the marine environment, and v) safe ut ilization of the ocean’s vast carbon storage and energy production potentials for CO2 mitigation and “super green” hydrogen generation.

AbstractThe Gorgon Joint Venture† made the Final Investment Decision (FID) for the Gorgon Project in September 2009. One element of that approval was the decision to proceed with the Carbon Dioxide Injection Project on Barrow Island, whereby CO2 separated from the reservoir gas from the Gorgon and Jansz-Io fields will be injected into a deep sandstone interval beneath Barrow Island.Since FID, the focus has been on delivering the project – this involves preparations for drilling and completing the four different well types, engineering design and procurement of the CO2 pipeline and procurement and manufacture of the CO2 compression system within the LNG plant.In addition to this engineering activity, the subsurface team has continued with improving their knowledge of the injection interval and overlying geology. The focus of this work has been two-fold:1.Deliver work to support the execution decisions, e.g. finalising well locations, well construction design, well completion design, reservoir data gathering plans, etc. In addition work has also been done to prepare for operations, focusing on understanding the behaviour of super- critical CO2 in the full system from the compressor to the reservoir as a basis for developing operations procedures and documents.2.Prepare for long term reservoir and project management; this includes developing a reservoir management plan with emphasis on surveillance data, continuing to develop the monitoring plans for understanding distribution of CO2 in the injection interval and continuing to evaluate and update understanding of subsurface uncertainties.We currently anticipate commissioning of the carbon dioxide injection system contemporaneous with the start-up of the second Gorgon LNG train in 2015. Between now and then the Carbon Dioxide Injection Project will drill and complete 17 wells, install a seven kilometre buried pipeline and associated facilities and construct, install and commission the CO2 compression system.* The Gorgon Joint Venture comprises the Australian subsidiaries of Chevron (47.3 percent), Exxon Mobil (25 percent), Shell (25 percent), Osaka Gas (1.25 percent), Tokyo Gas (1 percent) and Chubu Electric Power (0.417 percent). Chevron Australia is the operator of the Gorgon Project.

Abstract This paper presents an integrated numerical framework to co-optimize EOR and CO 2 storage performance in the Farnsworth field unit (FWU), Ochiltree County, Texas. The framework includes a field-scale compositional reservoir flow model, an uncertainty quantification model and a neural network optimization process. The reservoir flow model has been constructed based on the field geophysical, geological, and engineering data. A laboratory fluid analysis was tuned to an equation of state and subsequently used to predict the thermodynamic minimum miscible pressure (MMP). A history match of primary and secondary recovery processes was conducted to estimate the reservoir and multiphase flow parameters as the baseline case for analyzing the effect of recycling produced gas, infill drilling and water alternating gas (WAG) cycles on oil recovery and CO 2 storage. A multi-objective optimization model was defined for maximizing both oil recovery and CO 2 storage. The uncertainty quantification model comprising the Latin Hypercube sampling, Monte Carlo simulation, and sensitivity analysis, was used to study the effects of uncertain variables on the defined objective functions. Uncertain variables such as bottom hole injection pressure, WAG cycle, injection and production group rates, and gas-oil ratio among others were selected. The most significant variables were selected as control variables to be used for the optimization process. A neural network optimization algorithm was utilized to optimize the objective function both with and without geological uncertainty. The vertical permeability anisotropy (Kv/Kh) was selected as one of the uncertain parameters in the optimization process. The simulation results were compared to a scenario baseline case that predicted CO 2 storage of 74%. The results showed an improved approach for optimizing oil recovery and CO 2 storage in the FWU. The optimization process predicted more than 94% of CO 2 storage and most importantly about 28% of incremental oil recovery. The sensitivity analysis reduced the number of control variables to decrease computational time. A risk aversion factor was used to represent results at various confidence levels to assist management in the decision-making process. The defined objective functions were proved to be a robust approach to co-optimize oil recovery and CO 2 storage. The Farnsworth CO 2 project will serve as a benchmark for future CO 2 –EOR or CCUS projects in the Anadarko basin or geologically similar basins throughout the world.

AbstractPressure increases attendant with CO2 injection into the subsurface drive many of the risk factors associated with commercial- scale CCS projects, impacting project costs and liabilities in a number of ways. The area of elevated pressure defines the area that must be characterized and monitored; pressure drives fluid flow out of the storage reservoir along higher-permeability pathways that might exist through the caprock into overlying aquifers or hydrocarbon reservoirs; and pressure drives geomechanical changes that could potentially impact subsurface infrastructure or the integrity of the storage system itself. Pressure also limits injectivity, which can increase capital costs associated with installing additional wells to meet a given target injection rate. The ability to mitigate pressure increases in storage reservoirs could have significant value to a CCS project, but these benefits are offset by the costs of the pressure mitigation technique itself. Of particular interest for CO2 storage operators is the lifetime cost of implementing brine extraction at a CCS project site, and the relative value of benefits derived from the extraction process. This is expected to vary from site to site and from one implementation scenario to the next. Indeed, quantifying benefits against costs could allow operators to optimize their return on project investment by calculating the most effective scenario for pressure mitigation. This work builds on research recently submitted for publication by the authors examining the costs and benefits of brine extraction across operational scenarios to evaluate the effects of fluid extraction on injection rate to assess the cost effectiveness of several options for reducing the number of injection wells required. Modeling suggests that extracting at 90% of the volumetric equivalent of injection rate resulted in a 1.8% improvement in rate over a non-extraction base case; a four-fold increase in extraction rate results in a 7.6% increase in injection rate over the no-extraction base case. However, the practical impacts on capital costs suggest that this strategy is fiscally ineffective when evaluated solely on this metric, with extraction reducing injection well needs by only one per 56 (1x case) or one per 13 (4x case).

AbstractThe two tank molten salt thermal storage system is widely used in the commercialized solar thermal power plant. However, the thermocline storage system with a low-cost filler material is a more economically feasible option. In this study, a transient two-dimensional and two-temperature model is developed to investigate the heat transfer and fluid dynamics in a molten salt thermocline thermal storage system. After model validation, the effects of inlet flow boundary condition and storage medium properties including fluid and solid materials on the thermal performance of thermocline storage system are investigated. The results show that thermoclne thickness increases slowest with solar salt as heat transfer fluid (HTF) and Cofalit® as solid material in the thermocline tank. Any non-uniformity in the inlet velocity flow would only enhance mixing and widen the thermocline appreciably, which contributes to the loss of thermodynamic availability of stored energy. The thermocline thickness increases with the non-uniformity of the inlet velocity boundary condition. So smaller non-uniformity of inlet flow is better in non-uniform flow though it may causes larger fluctuations in average outlet temperature. Smaller inlet mass flow rate is better for the thermocline storage tank, while it also causes smaller discharging power. With the chosen basic design parameters such as fluid and solid materials, the size of a 2MWh thermocline tank is determined by a simple one-dimensional design method. Tank with larger H/D ratio has higher discharge efficiency. It helps to figure out the thermal stratification mechanism of a storage tank and thereby to determine optimum design and operating conditions.

Abstract Recently, the amount of Yogyakarta province municipal solid waste (MSW) came into Piyungan landfill site stood at around 470 ton/day consisting of 77% organic and 23% inorganic fractions. Annually, there was an increase as many as 8% per annum for the amount of MSW. Reduction of the MSW can be "forced" in integrated waste management site (in Indonesia is called TPST) which was built in the municipal level. In each TPST, there are two main activities which are Recycling and Composting. Both scenarios assume that 23% of inorganic waste can be recycled so that the subsequent need is to manage organic waste. Based on these considerations, calculations performed with: 1). Scenario 1: The TPST has been operated but there is no waste reduction at the source; 2). Scenario 2: TPST is operated and followed by solid waste reduction at the source. If the second scenario is applied, the amount of waste that goes to landfill Piyungan can be reduced up to 200 ton/day. Actually, scenario 1 is the realistic one because of Indonesian’s culture. Unfortunately, as scenario 1 was highly dependent on the TPST, the number of TPST which must be built increase steadily that it can reach 60 units in 2030 which is impossible to find space in Yogyakarta province. If the second scenario is applied, the amount of waste that goes to Piyungan landfill site can be reduced gradually from 25% (1-3 years), 35% (4-7 years), and 50% (8-15 years) through composting activity. The challenge possessed by scenario 2 is how to force people reduce their own organic waste by composting activity.

AbstractPrevious studies of CO2 leakage from wells have assumed that either CO2 leaks into aquifers in the form of a radial lateral buoyant lateral plume of gaseous CO2 or as a lateral radial plume of CO2 dissolved water. These assumptions are not based on any actual observations of the nature of gas leakage from well bores. No direct information appears to exist on CO2 leakage from actual CO2 wells so to understand better this phenomenon. In fact the seminal papers on this topic may have chosen these models because of ease of mathematical manipu lation. A wide range of information on the nature of leakage of methane from natural gas wells has been compiled. Analysis of this evidence suggests that methane neither forms buoyant radial plumes of gas, nor radial plumes of dissolved methane. Rather methane appears to be transported dominantly vertically by a combination of bubble and slug flow. Bubble flow occurs by bubbles of methane (or CO2) gas buoyantly rising up fractures. Slug flow is initiated when multiple bubbles amalgamate in a fracture to form a film that moves as a single mass. Slugs have very low surface area and therefor minimize the dissolution of the gas phase. Both bubbles and slugs in fractures move in an essentially vertical direction. The evidence for bubble and slug flow of methane comes from a variety of observational sources including: 1) measurement of methane concentrations radially away from a leaking well over a period of years; 2) evidence of gas scavenging (a phenomenon that cannot occur if the gas is in the dissolved phase); and 3) observations of concentrated bubbles emerging immediately around a gas wells following a sub -surface blowout while measurements of dissolved methane in surrounding water wells demonstrated minimal methane concentrations.Methane gas has also be directly imaged by down-the-hole cameras, emanating from fractures in the side of a water well as a string of bubbles. In this case again little if any methane dissolution into the aquifer had occurred. As a result damage to vegetation around leaking natural gas wells is typically found to be a radial zone around the well head less than a meter in diameter. An assumption of rapid CO2 dissolution into aquifers assumes that there is intimate contact between CO2 and water or brine. If CO2, like methane is dominantly transported by a combination of bubble and slug flow then the surface area of CO2 exposed to the water phase will be relatively minimal and little dissolution will occur. If CO2 gas leaking from a well into an aquifer, behaves in a similar way to methane many of the negative environmental consequences (such as metal contamination resulting from dissolved CO2 lowering the aquifers pH), will not occur. This analogue, if applicable, has significant implications for how wells should be monitored for leakage. Current monitoring conceptualizations based on monitoring wells are probably not the best approach.