bluuebunny/crossref_metadata_2025_split huggingface dataset:
Permeability Estimation for Large-Scale Potential CO2 Leakage Paths in Wells Using a Sustained-Casing-Pressure Model
Authors: Tao Qing , Checkai Dean , Bryant Steven L. 
Published: February 2011

Abstract
Large-scale geological storage of CO2 is likely to bring CO2 plumes into contact with a large number of existing wellbores. Estimating the flux of CO2 along a leaking wellbore requires a model of fluid properties and of transport along the leakage pathway. Wells that exhibit sustained casing pressure (SCP) in an intermediate annulus have a leakage path along a cement/steel interface, or within the cement in the annulus. The former path is analogous to a leakage path along a cement/earth interface outside the casing. The latter path can occur in cement outside the casing. Thus the likely magnitude of the permeability of leakage paths outside the well can be estimated from the permeability of these analog paths. A sustained casing pressure (SCP) model yields information about effective permeability of the pathway.
By choosing reasonable ranges for other well construction parameters, we apply the SCP model to obtain a range of effective permeabilities for a well based on a measured casing pressure build up history. We illustrate the approach with several field examples. For a relatively slow pressure build up (several psi/day), the permeability of the leakage path is in the range of microdarcy to hundreds of microdarcy. Fast pressure build up (thousands psi/day) indicates permeabilities in the range of tens of millidarcy to hundreds of millidarcy.
To account for the uncertainty in wellbore construction parameters, we calculate the distribution of effective permeability of a leaky well using Monte-Carlo simulation. The resulting permeability shows an approximately log-normal distribution skewed toward the maximum possible value. The expected value and a confidence interval are obtained for each well, which represents the most probable permeability of the well for a given pressure build up. For the wells studied here the expected values range from 10 microdarcy to 100 millidarcy. The expected leakage path permeability correlates reasonably well with pressure build up rate. This is to be expected from Darcy’s law, and thus a strong correlation between leakage path permeability and other characteristics of the wells in this sample does not exist. Obtaining the statistics of the expected leakage path permeability will thus require more observations of SCP wells.
The effective permeability of a leaky well is essential in calculating the CO2 leakage flux. Under the assumption that a leaky well encountered by a CO2 plume has a leakage pathway with the similar properties to an SCP well, we calculate the CO2 flux for the best, worst and most probable scenarios for the example wells. In the most probable scenario of CO2 flux, we calculate the expected CO2 leakage rate. Slow leakage yields a 0.1 kg/y CO2 rate while fast leakage could have a rate of 1000 kg/y.
Experimental Study on Optimum Half-Cycle Slug Size of Water Alternating Gas Under Tertiary Miscible Carbon Dioxide Flooding
Authors: Nuryaningsih L.. , Jiang H.. , Adidharma H.. 
Published: February 2011

AbstractThe effect of half cycle slug size (HCSS) on Water Alternating Gas (WAG) performance in tertiary miscible carbon dioxide (CO2) flooding is experimentally investigated. Different half cycle slug size influences the fluids mobility and the contact time between the injected fluids and oil, and hence to achieve the best possible displacement efficiency, an optimum water/gas half cycle slug size could exist and deserves investigation.Coreflood experiments are performed in Berea sandstone core, from which the WAG performance, such as percent oil recovery, tertiary recovery factor, and CO2 utilization factor are determined. The core flooding experiments are conducted at 60 °C and at miscible condition, i.e., at a pressure 20% above the minimum miscible pressure (MMP) of the oil sample. The experiments utilize Cottonwood Creek crude oil and artificial brines. The injection and connate brine contain 33.33 wt% CaCl2 and 66.67 wt% NaCl with salinities of 16000 ppm (mg/L) and 30000 ppm, respectively. In every core flood test, alternate cycles of brine and CO2 with a WAG ratio of 1:1 are injected with half cycle slug size ranging from 0.05 to 0.75 PV.The results show that for the system of interest, the optimum HCSS is 0.1 PV, in which the CO2 usage is only 0.6 PV to reach a high tertiary oil recovery of 40.63%. An HCSS higher or lower than 0.1 PV gives lower oil recovery. When HCSS is lower than 0.1 PV, the system gives lower oil recovery because some of the gas is trapped by water and keeps staying in the core instead of displacing oil. Meanwhile, an HCSS higher than 0.1 PV results in larger clusters of CO2 and water, thus water inefficiently controls CO2 mobility, which makes the CO2-oil contact time and interfacial area for mass transfer decrease and gas breakthrough occurs prematurely.This experimental study is an essential effort to obtain better understanding the effect of half cycle slug size on WAG performance, which has never been experimentally investigated before. The understanding is critical for optimizing the WAG performance.
Effect of Aquifer Heterogeneity, Brine Withdrawal, and Well-Completion Strategy on CO2 Injectivity in Shallow Saline Aquifer
Authors: Tiamiyu O. M. , Nygaard R.. , Bai B.. 
Published: February 2011

Abstract
The most promising near term solution to reduce CO2 emissions is to capture the CO2 produced from coal and gas fired power plants and inject it into deeply buried saline aquifers. However a large amount of these plants are far away from deep sedimentary basins and therefore alternative solutions have to be sought. Detailed computer simulation, using compositional numerical model software CMG-GEMGHG, was used to study the effects of aquifer anisotropy (heterogeneity), well completion technique (perforation and well orientation), brine production and injection rates on CO2 injectivity, and capability to retain and store reasonably large amount of CO2 for an extended period of time. The objective of this study is to find the optimal combination of operational parameters (injection rates, well completion techniques and brine withdrawal strategy), and how the interplay of these parameters with aquifer anisotropy (heterogeneity) affects, and can be manipulated to optimally harness CO2 storage potential and leakage risk mitigation in shallow saline aquifers.
Injected CO2 exists in three main forms in the aquifer, supercritical, dissolved and aqueous forms with amount depending largely on prevailing formation pressure and the depth of well placement. Without brine withdrawal, horizontal injector wells with the vertical sections closed have higher CO2 injectivity compared to vertical and deviated wells with bottom half perforated. With brine withdrawal more CO2 was injected and anisotropy (heterogeneity) (Kv/Kh ratio) has significant effect on CO2 injectivity, but well perforation and orientation has negligible effect, except for an extended (85 years) injection period when aquifer pressure has reached the maximum allowable. The impact of anisotropy (heterogeneity) on CO2 injectivity was observed to decrease with increase on injection rate for injection well placed in uppermost layers. This study shows CO2 sequestration in shallow saline aquifer has significant potential. Results from this study can potentially provide guideline for well completion technique, injection rate and brine withdrawal strategy, depending on aquifer properties, that can be applied in CO2 sequestration in shallow saline aquifer.
Unique CO2-Injection Experience in the Bati Raman Field May Lead to a Proposal of EOR/Sequestration CO2 Network in the Middle East
Authors: Sahin S.. , Kalfa U.. , Celebioglu D.. 
Published: February 2011

AbstractFossil fueled power generation is the largest source of carbon dioxide (CO2), which could be captured and stored. Carbon capture and storage (CCS) is one of the most important emission reduction technologies available for large stationary CO2 sources. Depleted oil and gas fields and major CO2 sources nearby are ideal areas for large scale geological storage. Injection of CO2 into a depleted reservoir can enhance the recovery of hydrocarbons. The circumstances, in fact, dictate the CO2 enhanced oil recovery (EOR) industry and a power generation sector eager to magnify the mutually beneficial link between CO2-EOR and new industrial sources of CO2.In 1986, the TPAO (Turkish Petroleum Corporation) started the first large scale immiscible CO2 injection project in southeastern Turkey. Around one million tons per year of naturally occurring CO2 has been injected into the Garzan carbonates in the Bati Raman Field. A substantial increase in the production rate and ultimate recovery has been experienced and more is expected. The Bati Raman immiscible CO2 injection project has been acknowledged as one of the most unique and successful enhanced oil recovery (EOR) applications in the history of heavy oil in fractured limestone reservoirs.There are nearly 50 oilfields in Turkey, and a significant proportion of them would be potentially suitable for EOR. If sufficient volumes of CO2 were economically available, many of these could produce incremental oil for an extended period. It is a fact that sedimentary basins in the Middle East are typically carbonates and this limits the selection of EOR processes significantly. Having observed CO2 injection as an excellent choice for carbonates through the Bati Raman experience, one may extend the CO2 network idea to the whole region. This will not only activate the enormous EOR potential in the mature fields of the Middle East but also the permanent storage of CO2 through a common effort.The utilization of captured CO2 for EOR will become feasible if CO2 recovery plants with a higher CO2 content give an attractive CO2 delivery cost and emission rights can be traded in the carbon market which was introduced by the Kyoto Protocol. The major challenge would be how to formulate a working and acceptable model between petroleum and power sectors and, to establish a market mechanism to ensure that this system becomes economically feasible.
Quantifying the Risk of CO2 Leakage Through Wellbores
Authors: Loizzo M.. , Akemu O. A. , Jammes L.. , Desroches J.. , Lombardi S.. , Annunziatellis A.. 
Published: February 2011

AbstractLeakage through new or existing wellbores is considered a major risk for carbon dioxide (CO2) geological storage. Long-term effective containment of CO2 is required and the presence of millions of suspended or abandoned wells exacerbates the potential risk in mature hydrocarbon provinces. Accurate estimates of risk profiles can support the acceptance of geological storage and the adoption of economically effective risk prevention and mitigation measures.Reliable data about long-term containment of CO2 is almost non-existent, so wells that exhibit a similar risk profile (such as gas storage, gas production and steam injection) should be used as proxy to assess failure rates and consequences for cemented wellbores.Statistical data about occurrence of leaks and their consequences are analyzed to determine the risk profile of CO2 leaks. A smaller sample of data about leak rates is also analyzed to provide their statistical distribution. Rates and consequences are then compared to try and assess the order of magnitude of major and catastrophic leaks.Hydrothermal CO2 leaks in natural analogs are also reviewed to compare the distribution of leak rates and the consequences on health, safety and environment of CO2 releases to soil and atmosphere.Analysis of existing data will show that major leaks are likely to occur in less than 2 wells per 1,000, with the overwhelming majority of CO2 leaks being small and with limited or negligible consequences.Given their risk profile, CO2 wellbore leaks should be addressed through a routine risk management approach. Their frequent occurrence requires effective prevention measures, such as understanding leaks and adapting and deploying practices to minimize their occurrence. On the other hand, their low impact ensures maximum effectiveness of mitigation measures, such as monitoring: since leaks can be detected long before damage ensues, they can be observed to predict their long-term consequences and to plan the most effective intervention without unnecessary immediate operation shut-downs.In conclusion, the recommended course of action is to focus on risk prevention and early detection. This implies the evolution from a "no leaks" attitude (even for negligible leak consequences) to one that seeks no damage and relies on tight surveillance.
Tertiary Oil Recovery and CO2 Sequestration by Carbonated Water Injection (CWI)
Authors: Kechut N.I.. I. , Riazi M.. , Sohrabi M.. , Jamiolahmady M.. 
Published: February 2011

Abstract
The increasing availability of the anthropogenic carbon dioxide (CO2) and the drives to reduce its concentration in the atmosphere has increased the interest in CO2 injection for improving the oil recovery in maturing oil reservoirs. Many of these reservoirs are being waterflooded to sustain the oil production. Instead of injecting plain water, injecting carbonated (CO2-enriched) water could bring additional oil recovery and added benefit of safe storage of CO2. In carbonated water injection (CWI), CO2 is dissolved in the injected brine prior to injection and then transported through the reservoir by the flood water. As a single phase, carbonated water mobility contrast with oil is more favourable than in the CO2 gas-oil system thus improves sweep efficiency and retards CO2 breakthrough. The slightly higher density of the carbonated water than the unadulterated water would induce the injected CO2 to slump towards the bottom of the reservoir, eliminating the risk of buoyancy-driven leakage thus securing storage.
This paper presents the results of an integrated experimental and numerical simulation study of tertiary CWI. A series of high pressure flow visualisation and coreflood experiments as well as compositional simulation have been carried out to evaluate the process. A North Sea crude oil and brine were used at a pressure typical of real reservoir conditions.
The visualisation experiments in high-pressure glass micromodels reveal that the oil swelling from CO2 diffusion into the oil and the subsequent oil viscosity reduction, coalescence of the isolated oil ganglia and flow diversion due to flow restriction in some of the pores as a result of oil swelling and the resultant fluid redistribution are the main mechanisms of oil recovery by the tertiary CWI. There was also evidence of micromodel surface becoming more water wet that could also play a role in the oil recovery. The coreflood tests results clearly show that the post waterflood CWI could remobilize the remaining trapped oil in the watered-out core that leads to significant additional oil recovery. A very gradual (dissolved) CO2 breakthrough exhibited in this process is a significant advantage over the sudden CO2 breakthrough problem commonly faced in the conventional CO2 flooding. CWI is also highly potential as CO2 storage injection strategy as demonstrated by almost 50% of the total volume of CO2 injected (in carbonated water) was being stored at the end of the test. There is a challenge in simulating the physics of the CWI process using the commercially available reservoir simulators which will also be discussed.
A Survey of CO2-EOR and CO2 Storage Project Costs
Authors: Jablonowski C.. , Singh A.. 
Published: February 2011

Abstract
For CO2 enhanced oil recovery (CO2-EOR) and CO2 storage projects, cost estimates have wide-ranging impacts on site screening and feasibility studies, concept selection, development planning, and production optimization. Good cost estimating practice requires technical knowledge about the project, a comprehensive scope, and a systematic approach. However, the quality of a cost estimate is probably most dependent on the quality of the data on which it is based. In the case of CO2-EOR and CO2 storage projects (CO2 projects), cost estimators face significant challenges regarding the availability and quality of data. The purpose of this paper is to organize and consolidate information on capital and operational costs for CO2 projects. A review was undertaken to identify and describe sources for cost data by major project components. There are sections for drilling, surface facility capital cost, and operation and maintenance cost. This survey can serve as a departure point for CO2 project cost estimators.
Saline Reservoir Storage in an Active Oil Field: Extracting Maximum Value From Existing Data for Initial Site Characterization, Southeast Regional Carbon Sequestration Partnership (SECARB) Phase IIII Anthropogenic CO2 Test at Citronelle Field
Authors: Petrusak R.. , Cyphers S.. , Bumgardner S.. , Hills D.. , Pashin J.. , Esposito R.. 
Published: February 2011

AbstractFor large-scale carbon dioxide (CO2) injection and storage, saline formations offer vast storage capacity, often in multiple geologic formations, or multiple storage reservoir horizons within a single formation. Challenges for characterizing CO2 storage reservoirs in specific saline formations may include limited subsurface data, unproven geologic traps and lack of any production infrastructure available for injection and monitoring operations. Active oil fields offer advantages for CO2 sequestration in saline formations that address such challenges. Advantages of active oil fields include proven structural traps and reservoir seals; confirmed saline storage horizons; existing field data including geophysical well logs, seismic data, core data, formation water analyses and reservoir pressure tests; existing infrastructure for access and monitoring; and potential use of CO2 in enhanced oil recovery. Such advantages are substantial, but active oil fields can also present unique hurdles for CO2 storage in saline formations. These include old and incomplete well data and geophysical logs; confirming the integrity of cement through the saline formation and confining unit (if located above the oil reservoir); and remediating existing wells.The Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III Anthropogenic Test is a large-scale demonstration of integrated CO2 capture, transport and storage planned for Citronelle field, in Mobile County, Alabama.1 Anthropogenic CO2 from a coal-fired electric generating plant, Alabama Power’s Plant Barry, will be captured and transported to Citronelle field.2 During 2011 to 2014, up to 182,500 tonnes of CO2 will be injected annually into the Lower Cretaceous Paluxy Formation, a saline formation that contains multiple reservoir sandstones and is located above the oil reservoir. This paper describes the initial characterization effort, which used all available field and regional data, to build a reservoir framework for the Paluxy Formation at Citronelle for initial assessment of injectivity, storage capacity and fate of injected CO2. The initial characterization of the Paluxy Formation demonstrates a successful approach for estimating key saline reservoir parameters including porosity, permeability, sand thickness and continuity from an incomplete existing data set in an active oil field. A robust geologic data collection effort is planned for the CO2 injection and observation wells to be drilled at the Anthropogenic Test site during 2011. The new data will be integrated with the existing Paluxy data set at Citronelle field to validate, refine and expand the initial characterization of the CO2 storage reservoir sandstones.
Thermal Aspects of Geomechanics and Induced Fracturing in CO2 Injection With Application to CO2 Sequestration in Ohio River Valley
Authors: Goodarzi S.. , Settari A.. , Zoback M.. , Keith D. W. 
Published: February 2011

Abstract
Ohio River Valley is considered a potential site for CO2 storage since it is in close proximity to large CO2 emitters in the area. In a CO2 storage project, the temperature of the injected CO2 is usually considerably lower than the formation temperature. The heat transfer between the injected fluid and rock has to be investigated in order to test the viability of the target formation to act as an effective storage unit and to optimize the storage process.
A coupled flow, geomechanical and heat transfer model for the potential injection zone and surrounding formations has been developed. All the modeling focuses on a single well performance and considers induced fracturing for both isothermal and thermal injection conditions. The induced thermal effects of CO2 injection on stresses, displacements, fracture pressure and propagation are investigated. Possibility of shear failure in the caprock resulting from heat transfer between reservoir and the overburden layers is also examined.
Displacements will be smaller for the thermal model compared to isothermal model. In the thermal case, the total minimum stress at the wellbore decreases with time and falls below the injection pressure quite early during injection. Therefore, fracturing occurs at considerably lower pressure for the thermal model. The coupled thermal and dynamic fracture model shows that thermal effects of injection could increase the speed of fracture propagation in the storage layer depending on the injection rate. These phenomena are dependent primarily on the difference between the injection and reservoir temperature. An optimization algorithm for injection temperature is discussed based on limiting the maximum fracture length and minimizing the risk of leakage from thermal effects of CO2 storage while improving the injection capacity.
Incorporation of thermal effects in modeling of CO2 injection is significant for understanding the dynamics of induced fracturing in storage operations. Our work shows that the injection capacity with cold CO2 injection could be significantly lower than expected, and it may be impractical to avoid induced fracture development. In risk assessment studies inclusion of the thermal effects will help prevent the unexpected leakage in storage projects. The methodology developed will play an important role in process optimization for maximizing the injection capacity while maintaining the safety of storage.
Experimental Evaluation of the Flue-Gas Injection of Barrancabermeja Refinery as EOR Method
Authors: De La Ossa J. E. , Wallens A. Bejarano , Anaya A. Florez , Santos N. S. 
Published: February 2011

Abstract
Because of its petrochemical processes Barrancabermeja refinery produces a considerable amount of flue gas daily. The Llanito oil field has an original oil volume of 314 million barrels (MBls) and it has produced 37.9 MBls up to December 2009, which corresponds to a recovery factor of only 12%, being really low for 50 years of exploitation.
The application of an enhanced oil recovery process represents an alternative for improving the final recovery factor. The availability of sources (Water, gas, chemicals, steam, etc) and the reservoir characterization dictate the feasibility of the project according to a study carried out. An environmentally undesirable by-product resulting from refining processes such as flue gas (Nitrogen + CO2) becomes important when used as raw material in the secondary or tertiary recovery of oil which affects the increase in production and the final recovery of hydrocarbons.
This study evaluated experimentally the effect of the injection of the Barrancabermeja refinery´s flue gas as an enhanced oil recovery method applied to B Sandstone of the Llanito oil field. The volume of the refinery´s flue gas was characterizated and calculated; a study of fluid-fluid interaction was carried out between the flue gas and petroleum at reservoir conditions. The interaction between reservoir fluid and the porous media was evaluated and the best flue gas injection mechanism was determined in order to increase the recovery factor for the B sands of Llanito oil field. In addition to increase the final recovery factor, the study aims to reducing flue gas emissions and consequent environmental benefit.