Jiemin Lu

Long-term performance of a mudrock seal in natural CO2 storage

The ability of mudrock seals to prevent CO 2 leakage is a major concern for geological storage of anthropogenic CO 2 . The long-term performance of a mudrock seal, which provides a natural analogue, in the North Sea Miller oil fi eld has been evaluated. This mudrock seal is immediately above a natural CO 2 -rich reservoir. The paper reports the stable isotopes of carbon from carbonate minerals in the mudrock that have precipitated in contact with CO 2 during 4 km of burial. A well-defi ned linear trend of upward-decreasing δ 13 C traces the progressive penetration of free-phase CO 2 causing dissolution and reprecipitation of carbonate minerals. The CO 2 was emplaced ca. 70‐80 Ma, and has only penetrated 12 m vertically in this case. The infi ltration rate is estimated as ~9.8 ◊ 10 ‐7 g cm ‐2 yr ‐1

Potential impacts of CO2 leakage on groundwater chemistry from laboratory batch experiments and field push-pull tests.

Storage of CO2 in deep saline reservoirs has been proposed to mitigate anthropogenically forced climate change. If injected CO2 unexpectedly migrates upward in shallow groundwater resources, potable groundwater may be negatively affected. This study examines the effects of an increase in pCO2 (partial pressure of CO2) on groundwater chemistry in a siliclastic-dominated aquifer by comparing a laboratory batch experiment and a field single-well push-pull test on the same aquifer sediment and groundwater. Although the aquifer mineralogy is predominately siliclastic, carbonate dissolution is the primary geochemical reaction. In the batch experiment, Ca concentrations increase until calcite saturation is reached at ~500 h. The concentrations of the elements Ca, Mg, Sr, Ba, Mn, and U are controlled by carbonate dissolution. Silicate dissolution controls Si and K concentrations and is ~2 orders of magnitude slower than carbonate dissolution. Changing pH conditions through the experiment initially mobilize Mo, V, Zn, Se, and Cd; sorption reactions later remove these elements from solution and concentrations drop to pre-experiment levels. The EPAs primary and secondary MCLs are not exceeded except for Mn, which exceeded the EPAs secondary standard of 0.05 mg/L. Push-pull results also identify carbonate and silicate dissolution reactions ~2 orders of magnitude slower than batch experiments.

A harmonic pulse testing method for leakage detection in deep subsurface storage formations

Detection of leakage in deep geologic storage formations (e.g., carbon sequestration sites) is a challenging problem. This study investigates an easy-to-implement frequency domain leakage detection technology based on harmonic pulse testing (HPT). Unlike conventional constant-rate pressure interference tests, HPT stimulates a reservoir using periodic injection rates. The fundamental principle underlying HPT-based leakage detection is that leakage modifies a storage systems frequency response function, thus providing clues of system malfunction. During operations, routine HPTs can be conducted at multiple pulsing frequencies to obtain experimental frequency response functions, using which the possible time-lapse changes are examined. In this work, a set of analytical frequency response solutions is derived for predicting system responses with and without leaks for single-phase flow systems. Sensitivity studies show that HPT can effectively reveal the presence of leaks. A search procedure is then prescribed for locating the actual leaks using amplitude and phase information obtained from HPT, and the resulting optimization problem is solved using the genetic algorithm. For multiphase flows, the applicability of HPT-based leakage detection procedure is exemplified numerically using a carbon sequestration problem. Results show that the detection procedure is applicable if the average reservoir conditions in the testing zone stay relatively constant during the tests, which is a working assumption under many other interpretation methods for pressure interference tests. HPT is a cost-effective tool that only requires periodic modification of the nominal injection rate. Thus it can be incorporated into existing monitoring plans with little additional investment.

Regional assessment of CO2-solubility trapping potential: A case study of the coastal and offshore Texas Miocene interval

This study presents a regional assessment of CO2-solubility trapping potential (CSTP) in the Texas coastal and offshore Miocene interval, comprising lower, middle, and upper Miocene sandstone. Duans solubility model [Duan et al. Mar. Chem. 2006, 98, 131-139] was applied to estimate carbon content in brine saturated with CO2 at reservoir conditions. Three approaches (simple, coarse, and fine) were used to calculate the CSTP. The estimate of CSTP in the study area varies from 30 Gt to 167 Gt. Sensitivity analysis indicated that the CSTP in the study area is most sensitive to storage efficiency, porosity, and thickness and is least sensitive to background carbon content in brine. Comparison of CSTP in our study area with CSTP values for seven other saline aquifers reported in the literature showed that the theoretical estimate of CO2-solubility trapping potential (TECSTP) has a linear relationship with brine volume, regardless of brine salinity, temperature, and pressure. Although more validation is needed, this linear relationship may provide a quick estimate of CSTP in a saline aquifer. Results of laboratory experiments of brine-rock-CO2 interactions and the geochemical model suggest that, in the study area, enhancement of CSTP caused by interactions between brine and rocks is minor and the storage capacity of mineral trapping owing to mineral precipitation is relatively trivial.

Geochemical interactions of shale and brine in autoclave experiments—Understanding mineral reactions during hydraulic fracturing of Marcellus and Eagle Ford Shales

Geochemical interactions between shale and hydraulic fracturing fluid may affect produced-water chemistry and rock properties. It is important to investigate the rock–water reactions to understand the impacts. Eight autoclave experiments reacting Marcellus and Eagle Ford Shale samples with synthetic brines and a friction reducer were conducted for more than 21 days. To better determine mineral dissolution and precipitation at the rock–water interface, the shale samples were ion milled to create extremely smooth surfaces that were characterized before and after the autoclave experiments using scanning electron microscopy (SEM). This method provides an unprecedented level of detail and the ability to directly compare the same mineral particles before and after the reaction experiments. Dissolution area was quantified by tracing and measuring the geometry of newly formed pores. Changes in porosity and permeability were also measured by mercury intrusion capillary pressure (MICP) tests. Aqueous chemistry and SEM observations show that dissolution of calcite, dolomite, and feldspar and pyrite oxidation are the primary mineral reactions that control the concentrations of Ca, Mg, Sr, Mn, K, Si, and SO4 in aqueous solutions. Porosity measured by MICP also increased up to 95%, which would exert significant influence on fluid flow in the matrix along the fractures. Mineral dissolution was enhanced and precipitation was reduced in solutions with higher salinity. The addition of polyacrylamide (a friction reducer) to the reaction solutions had small and mixed effects on mineral reactions, probably by plugging small pores and restricting mineral precipitation. The results suggest that rock–water interactions during hydraulic fracturing likely improve porosity and permeability in the matrix along the fractures by mineral dissolution. The extent of the geochemical reactions is controlled by the salinity of the fluids, with higher salinity enhancing mineral dissolution.

A Preliminary Simulation of CO2-EOR and Storage in One Heavy Oil Carbonate Oilfield Offshore Guangdong, China

This paper presents the first study on CO2-EOR potential of the LH11-1 oilfield offshore Guangdong Province, China. LH11-1 field is a reef heavy oilfield (16–23° API), and overall development efficiency is not ideal. In this study, the CO2 flooding potential in LH11-1 field was evaluated through a compositional simulation using the Petrel and CMG-GEM tools. A detailed fluid characterization was performed to accurately represent the reservoir fluid. 1D slim tube and core flood simulations were interpreted to understand the physical mechanisms of oil recovery. A reservoir geological (structure, facies and fluids) model was constructed in Petrel system and the model was calibrated using manual and assisted history matching methods. The natural depletion and continuous CO2 injection scenarios were simulated by GEM. Results indicate that the minimum miscibility pressure (MMP) of crude oil in Liuhua field is approximately 20 MPa. Therefore, the mechanism of oil recovery by CO2 EOR in Liuhua field should be suitable for immiscible CO2 flooding. The continuous CO2 injection would recover an incremental 7% of OOIP in Liuhua field, and the CO2 storage efficiency is relatively high with more than 95.5% of injection CO2 has been stored in the reservoir which indicate an important significance for CO2-EOR and storage potential in offshore carbonate oilfield.

Field Observations of Geochemical Response to CO2 Injection at the Reservoir Scale

Abstract Geochemical change in pore-fluid composition of the storage formation is one of the major long-term instabilities introduced during CO2 storage. Field investigation of CO2–water–rock interactions has been a component in many of the experimental and pilot tests conducted in preparation for future large-volume storage. Geochemical data collected at eight injection sites (Weyburn, Nagaoka, Frio, Cranfield, Otway, Ketzin, Illinois Basin Decatur [IDB], and Citronelle) document CO2 dissolution and the interaction of these fluids with minerals. Outcomes of these in-reservoir tests show that CO2–water–rock reactions generally occur as expected from theory and laboratory experiments, i.e. they are dominated by CO2 rapid dissolution into brine, carbonate dissolution, and slower silicate dissolution. Flow properties and mechanical integrity of the storage and seal formations in conventional carbonate and siliciclastic sediments tested have not been shown to be detrimentally affected by CO2-induced reactions. Uncertainties about the process and magnitude of geochemical stabilization, in particular the amount of CO2 that is dissolved during injection and long-term stabilization, are noted. Field observations have not been undertaken to limit these uncertainties, and significant difficulties in collecting relevant data may limit the potential for resolving these issues with conventional sampling programs. It is not clear if in any field cases these uncertainties are material to the performance of a storage facility in terms of retaining CO2 or assuring no unacceptable risks. Overall, field observations suggest that while of value in research-oriented projects, investment in characterization and monitoring of rock-fluid responses to CO2 injection can be decreased for commercial projects.