Mexico has undertaken a series of measures to implement Carbon Capture and Storage (CCS) technology due to the acquired national and international commitments regarding the reduction of GHG emissions as well as their implications to climate change. So far, the screening of the different methods for geological storage of CO2 potentially applicable in Mexico includes deep saline aquifers, non-economic coal beds, and crude oil reservoirs for EOR.
Storage of carbon dioxide projects in igneous rocks has been successful in the past. According to the literature, there are about eight sites, onshore, in the world with plenty of igneous rocks to store CO2, and Mexico is one of these sites. However, little attention has been paid to the study of igneous rocks as a potential method for geological storage of carbon dioxide.
This work aims the first petrographic and geochemical analysis to estimate the feasibility of CO2 mineralization thorough Mexican basaltic formations. This analysis includes the identification of the main CO2 emission areas in Mexico, the collection of samples near to large CO2 emissions sites and, the characterization of the samples by different tests and techniques. The properties of the rock samples and water were studied after the tests to compare changes in mineral phases and water composition.
The results herein confirm the feasibility of Mexican basalts to react in the presence of CO2 but also set the recommendations for the next steps to take to determine the technical feasibility of the CO2 permanent storage using basalts in Mexico.
Results of the Integrated CCS for Kansas pre-feasibility study indicate that large-scale CO2 capture, transportation and storage in saline aquifers in Kansas is both technically and economically feasible and deserving of further study. Based on the technical work on multiple geologic sites, there appear to be up to four sites within the North Hugoton Storage Complex (NHSC) in Southwest Kansas where >50 million tons CO2 could be injected over a 25- to 30-year period and safely stored in a set of stacked saline aquifers at ideal depths of 5200-6400 ft. The saline aquifers (Mississippian Osage, Ordovician Viola, and Cambrian-Ordovician) are overlain by oil reservoirs that are candidates for CO2 Enhanced Oil recovery (EOR). Of the four possible sites in the NHSC, the Patterson site was chosen as the primary site for a CarbonSAFE Phase II project. Patterson was chosen because the operator of the overlying fields, Berexco, was a long-term research partner of the Kansas Geological Survey (KGS), having participated in several DOE-funded studies with the KGS. Patterson has EOR opportunities in overlying reservoirs and most of the prospective injection site is already unitized.
Capture, compression and transportation of large volumes of CO2 is economic in the region, particularly since the extension and expansion of Federal 45Q tax credits in February 2018 that provide $35/ton for CO2 stored during EOR and $50/ton if stored in a saline reservoir and can be captured for a 12-year period. Without these credits, saline aquifer storage is not economically viable. The most economic scenario involves CO2 aggregated from multiple ethanol plants via small-diameter pipelines that tie into a main trunk line for delivery to market. CO2 EOR likely needs to be part of the system to provide economy of scale and, potentially, additional subsidy for saline aquifer injection through CO2 sales. High capture costs at the two power plants and refinery in this study make them non-economic options without further subsidy that may arise from a large regional pipeline system.
Legal, regulatory, public policy aspects of a project of the scale envisioned will require significant changes at the State level. In particular, legislation that would regulate capture, transportation, injection and storage as a public utility would be required along with allowances for eminent domain to be used for pipeline right-of-way and pooling of pore space. Streamlining the U.S. EPA UIC Class VI well permit process and/or establishing State primacy would further support development of commercial-scale CCS. Effective public outreach is critical for support of State regulatory changes, and for public acceptance, particularly in light of possibility for induced seismicity due to injection in certain areas and mixed public opinions about pipeline construction.
Md Jalil, Abdullah Al Mubarak (PETRONAS Research Sdn Bhd) | Mat Isa, M Faudzi (PETRONAS Research Sdn Bhd) | Rostani, Khairul (PETRONAS Research Sdn Bhd) | Othman, Nurzatil Aqmar (PETRONAS Research Sdn Bhd) | M Shariff, Azmi (Universiti Teknologi PETRONAS) | Lau, Kok Keong (Universiti Teknologi PETRONAS) | Partoon, Behzad (Universiti Teknologi PETRONAS) | Tay, Wee Horng (Universiti Teknologi PETRONAS)
As easy gas resources around the world are depleting; high Carbon Dioxide (CO2) gas fields are thrust into the spotlight to become new candidates for field development. However, the presence of oftentimes sizable Carbon Dioxide contents in the gas reservoir (can be up to 80% volumetric) introduced a huge technical and economic challenges towards the field exploitation.
Over the last few years, several studies have been conducted on cryogenic technologies such as cryogenic distillation and supersonic nozzle in CO2 separation for fields containing more than 40% of CO2. Based on the studies, these new cryogenic technologies have shown to have high potential in separating CO2 from natural gas offshore to be utilized under carbon, capture, storage and utilization (CCUS) project.
The new cryogenic technologies are currently being tested for the proof of concept. Hence, a pilot plant, which is a scaled down version of the technology was developed. One of the major challenges faced during the pilot plant testing is the emergency depressurization philosophy as the process involves CO2 solids handling which is uncommon to the industry standard. Depressurization of high CO2 fluid at cryogenic temperature would lead to possibility of CO2 solids formation, hence potential blockage of process equipment and venting line.
Therefore, this paper will focus on the design of the pressure relieving system of such a facilities. It would also touched on the implementation of the pressure relieving system during the operation of the pilot tests and as well as the tests designed specially to test the pressure relieving system. Finally the paper would give a few proposals on improvements to be made to such system. It is also the ultimate aim of the authors and the team to introduce a new philosophy for Cryogenic CO2 Blowdown system to the process industry.
Tavassoli, Shayan (The University of Texas at Austin) | Krishnamurthy, Prasanna (The University of Texas at Austin) | Beckham, Emily (The University of Texas at Austin) | Meckel, Tip (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Storage of large amounts of CO2 within deep underground aquifers has great potential for long-term mitigation of climate change. The U.S. Gulf Coast is an attractive target for CO2 storage because of the favorable formation properties for injection and containment of CO2. Deltaic formations are one of the primary targeted depositional environments in the Gulf Coast. This paper investigates CO2 storage in deltaic saline aquifers through a combination of geological modeling and flow simulation.
The geological model in our study is developed based on a laboratory-scale 3D flume experiment replicating the formation of a delta structure and populated with geologic properties according to Miocene Gulf of Mexico natural analogues. We used invasion percolation simulations to understand the gravity- driven flow and the relationship between architecture, stratigraphy, and fluid migration pathways. The results were used to develop an upscaled model for compositional simulation with the key features of the original geological model and to determine injection schemes that maximize the injection capacity and minimize the amount of mobile CO2 in the formation. In order to achieve this, we used compositional reservoir simulations to study the pressure-driven flow and phase behavior.
The results of invasion percolation simulations were used to identify the key stratigraphic units affecting CO2 migration. The realistic geometries and high resolution of the model facilitate the transfer of results from synthetic to subsurface data. The results allow for the analysis of deltaic depositional environments, important stratigraphic surfaces, and their impact on CO2 storage. The reservoir simulation model and phase behavior were validated against available field and lab data. The results of reservoir simulations were used to investigate the effects of main mechanisms, such as gas trapping and solubilization, on storage capacity. We compared our simulation results on the basis of invasion percolation (gravity driven) and reservoir simulation (pressure driven). The comparison is helpful to understand the strengths and weaknesses of each approach and determine best practices to evaluate CO2 migration within similar formations.
The unique and extremely well characterized deltaic model allows for unprecedented representation of the depositional aquifer architecture. This research combines geologic modeling, flow simulation, and application for CO2 storage. The integrated conclusions will constrain predictions of actual subsurface flow performance and CO2 storage capacity in deltaic systems, while identifying potential risks and primary stratigraphic migration pathways. This research gives insights on prediction of CO2 storage performance and characterization of prospective saline aquifers.
Most shale producers in North America have given little thought to the flowback stage following hydraulic fracturing. Others have come to realize it represents a valuable opportunity to learn more about their wells. A rigorous modeling approach is developed for effective management and inventory analysis of natural-gas storage in underground salt caverns.
Local officials are calling on Massachusetts Gov. Charlie Baker to require studies of health and safety risks before approving new natural-gas infrastructure. In separate letters, boards of health representing 100 communities raise concerns about the state's reliance on natural gas as a fuel source. North Dakota oil drillers are falling far short of the state’s goals to limit the burning of excess natural gas at wellheads, 5 years after the state adopted the rules to reduce the wasteful and environmentally harmful practice. A new integrated modeling tool helps Canada analyze methane emissions to get a better understanding of the economic and environmental implications. While much progress has been made to reduce flaring, associated gas continues to be flared at thousands of oil production sites around the world.
CCUS is an interdisciplinary research field and its broad scope means that CCUS offers numerous opportunities for science and engineering graduates, including petroleum engineers. Underbalanced coiled tubing drilling has continually advanced since the first trials in the 1990s but remains a relatively niche drilling technology. With UBCTD projects set to start in many countries next year, this technology may be seeing a turning point.