Storage In Oil Fields Research Articles

Probabilistic Gas Leak Rate Estimation Using Submodular Function Maximization With Routing Constraints

Harmful greenhouse gases such as methane are prone to leak during extraction, transportation, and storage in oil fields. Therefore we must monitor gas leak rates to keep such fugitive emissions in check. However, most currently available approaches incur significant computational costs to generate informative paths for mobile sensors and estimate leak rates from the collected data. As such, they do not scale to large oil fields and are infeasible for real-time applications. We address these problems by deriving an efficient analytical approach to compute the leak rate distribution and Expected Entropy Reduction (EER) metric used for path generation. Moreover, a faster variant of a submodular function maximization algorithm is introduced, along with a generalization of the algorithm to find informative data collection walks with arc routing constraints. Our simulation experiments demonstrate the approach’s validity and substantial computational gains.

Pore-scale mechanisms of CO2 storage in oilfields

Rapid implementation of global scale carbon capture and storage is required to limit temperature rises to 1.5 °C this century. Depleted oilfields provide an immediate option for storage, since injection infrastructure is in place and there is an economic benefit from enhanced oil recovery. To design secure storage, we need to understand how the fluids are configured in the microscopic pore spaces of the reservoir rock. We use high-resolution X-ray imaging to study the flow of oil, water and CO2 in an oil-wet rock at subsurface conditions of high temperature and pressure. We show that contrary to conventional understanding, CO2 does not reside in the largest pores, which would facilitate its escape, but instead occupies smaller pores or is present in layers in the corners of the pore space. The CO2 flow is restricted by a factor of ten, compared to if it occupied the larger pores. This shows that CO2 injection in oilfields provides secure storage with limited recycling of gas; the injection of large amounts of water to capillary trap the CO2 is unnecessary.

Potential evaluation of CO2 EOR and storage in oilfields of the Pearl River Mouth Basin, northern South China Sea

AbstractThe Pearl River Mouth Basin (PRMB) is the largest petroliferous sedimentary basin in the northern South China Sea. It is near the coastal economic zone of Guangdong province where a large number of CO2 emission sources are located. Carbon dioxide enhanced oil recovery (EOR) represents an opportunity to promote offshore carbon capture, utilization and storage (CCUS) deployment because CO2 flooding offers a method to recover additional oil while simultaneously sequestering anthropogenic CO2. In this paper, a comprehensive multiparameter ‘quick look’ and potential evaluation method was proposed to screen and assess offshore CO2 EOR potential. A screening scheme for the CO2 EOR potential of reservoirs of the PRMB was also proposed using additional parameters, including reservoir properties and engineering design incorporating a dimensionless screen model and calculations. The results show that the suitability of reservoirs for CO2 EOR and storage varies and could be categorized into four priority grades. Approximately 30 of the oil reservoirs from 10 oilfields were preferentially identified by applying the screening method for reservoirs with predicted higher ultimate recovery potentials. It was predicted that 3227 × 104 t of additional oil could be produced from these reservoirs and that 3617 × 104 t of CO2 could be simultaneously stored. The sensitivity analysis shows that injection pressure (Pinj) would be more sensitive than production pressure (Pp) and well distance (L) on the CO2 EOR and storage efficiency, indicating that EOR operations with higher Pinj may improve oil production. The prospective reservoirs include those candidates with suitability grades of I and II from the Lufeng (LF) and Huizhou (HZ) oilfield clusters, where 1164 × 104 t of additional oil could be produced and 1464 × 104 t of CO2 stored with CO2 EOR. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd.

Pore Scale Observations of Trapped CO2 in Mixed-Wet Carbonate Rock: Applications to Storage in Oil Fields.

Geologic CO2 storage has been identified as a key to avoiding dangerous climate change. Storage in oil reservoirs dominates the portfolio of existing projects due to favorable economics. However, in an earlier related work ( Al-Menhali and Krevor Environ. Sci. Technol. 2016 , 50 , 2727 - 2734 ) , it was identified that an important trapping mechanism, residual trapping, is weakened in rocks with a mixed wetting state typical of oil reservoirs. We investigated the physical basis of this weakened trapping using pore scale observations of supercritical CO2 in mixed-wet carbonates. The wetting alteration induced by oil provided CO2-wet surfaces that served as conduits to flow. In situ measurements of contact angles showed that CO2 varied from nonwetting to wetting throughout the pore space, with contact angles ranging 25° < θ < 127°; in contrast, an inert gas, N2, was nonwetting with a smaller range of contact angle 24° < θ < 68°. Observations of trapped ganglia morphology showed that this wettability allowed CO2 to create large, connected, ganglia by inhabiting small pores in mixed-wet rocks. The connected ganglia persisted after three pore volumes of brine injection, facilitating the desaturation that leads to decreased trapping relative to water-wet systems.

CCU&S via Stacked Storage—case Studies from CO2-EOR Basins of the United States

Most compilations of global CO2 storage capacity separate volumes of storage in oil fields from volumes of storage in nonproductive saline formations. In this study we begin to define accessible volumes by strategically combining CO2 use for enhanced oil recovery with large-volume storage in associated saline formations. This variant of carbon capture, use, and storage (CCU&S) is known as stacked storage because it uses the three-dimensional properties of the subsurface to achieve multiple complementary objectives. The motivation for combining CO2 enhanced oil recovery (EOR) and saline-storage types is that where EOR is possible, it provides an attractive market for CO2 but does not alone achieve emission- reduction targets. By spatially and temporally linking CO2 EOR with vertically and horizontally adjacent saline storage volumes, the infrastructure, experience, and community acceptance developed for EOR can provide a substantive boost for using the entire subsurface for storage of very large volumes.Representative fields in major areas of current commercial CO2 EOR served as test cases and were matched with mapped subregional saline-storage potential. Test cases included (1) selected Permian and Pennsylvanian CO2 EOR fields in the Permian Basin of west Texas and New Mexico that were matched with regional, nonproductive Permian saline formations, (2) Cretaceous-age fields (e.g., the SECARB study area at Cranfield) in the Mississippi salt basin that were matched with regional Cretaceous Tuscaloosa saline formations, and (3) salt-dome marginal and growth-fault rollover fields in the Oligocene Frio Formation of the Texas Gulf Coast that were matched with regional Tertiary-age saline formation. In each case, good matches were obtained between CO2 EOR markets and adjacent saline formations. Other saline formations underlie and are separated from the productive zone by their own confining systems. Limitations on the application are also considered.

Using Chemical and Isotopic Data to Quantify Ionic Trapping of Injected Carbon Dioxide in Oil Field Brines

Injection of carbon dioxide into depleted oil fields or deep saline aquifers represents one of the most promising means of long-term storage of this greenhouse gas. While the ultimate goal of CO2 injection in the subsurface is mineral storage of CO2 as carbonates, short-term (<50 year) storage of injected CO2 is most likely to be accomplished by ionic trapping of CO2 as bicarbonate ions (HCO3-) and hydrogeological trapping of molecular CO2. Here, we demonstrate a technique for quantifying ionic trapping of injected CO2 as HCO3- using geochemical data collected prior to and during 40 months of CO2 injection into a hydrocarbon reservoir at the International Energy Agency (IEA) Weyburn CO2 Monitoring and Storage Project, Saskatchewan, Canada. As a result of injection of CO2 with a low carbon isotope ratio (delta13C value), fluid and gas samples from four selected production wells showed an increase in HCO3- concentration and a decrease in delta13C values of HCO3- and CO2 over the observation period. Isotope and mass balance calculations indicate that, after 40 months of injection, approximately 80% of the HCO3- in the reservoir brines sampled from the four wells formed via dissolution and dissociation of injected CO2. This chemical and isotopic technique should be applicable to CO2 injection and storage in oil fields and in deep saline aquifers, provided there is sufficient carbon isotopic distinction between injected CO2 and baseline aquifer HCO3- and CO2.

Service Experience of Glass-Reinforced Plastic Tanks

Abstract Previous reports had indicated that a glass mat reinforced polyester 250-barrel oil field storage tank showed little increase in circumferential measurement. It was found, however, that this tank suffered a tension failure at one of its staves and had to be scrapped after only 46 months' service. Data are given to show the results of circumferential measurements made on a glass-epoxy 250-barrel oil field stock tank in both the full and the empty condition over one winter and three summers. Results also are reported of circumferential measurements made on a full 500-barrel wash tank during two summers. The average increase in circumference between the first and second summer for the 500-barrel tank was 0.020 as compared to 0.006 feet for the 250-barrel tank. 7.5.5