Formation Brine Research Articles

Effect of CO2 on the dynamic and equilibrium interfacial tension between crude oil and formation brine for a deepwater Pre-salt field

Interfacial tension (IFT) between oil and brine is key to determine the Capillary Number, which governs capillary forces in the porous medium. As a result, changes in IFT affect the displacement efficiency and the residual oil saturation having direct impact on the Recovery Factor. Fluids in Pre-salt fields (offshore Brazil) have particular characteristics, such as high salinity in the brines, elevated content of asphaltenes and resins in the oils and high CO2 content in the produced gas for some fields. The effect of CO2 on the IFT depends on complex electrostatic and acid-base equilibria, and cannot be predicted by a single fluid property. This work presents the experimental study of the effect of CO2 dissolution on the IFT between a Pre-salt oil with a high total base number (TBN) and non-negligible total acid number (TAN) and a high salinity brine using the pendant drop technique. The oil and its asphaltenic fraction were characterized by Fourier-transform infrared spectroscopy, nuclear magnetic resonance spectroscopy, and elemental analysis identifying characteristic functional groups and indicating both acidic and basic polar functional groups. CO2 dissolution resulted in an IFT increase of 56% evidencing that, despite the high TBN of this oil, basic groups have low surface-activity. Moreover, a study of IFT as a function of pH showed that the maximum IFT was found in strongly acidic environments, but constant IFT values were obtained at neutral and basic pH values. Thus, the interfacial activity is governed by asphaltenes and resins with polar groups of varying acid/base behavior. The presence of CO2 also accelerated the dynamic behavior of IFT reducing the equilibrium time by 70%. This is caused by the reduction of oil viscosity, which impacts the relaxation time and enhances the diffusion of surface-active species towards the interface. The results in this work evidence that the CO2 content should be considered when modeling fluid properties for this type of reservoirs, as it affects the oil-brine IFT. In addition, for this oil with high content of surface-active compounds and non-negligible TAN and TBN, CO2 flooding does not contribute to reduce the IFT. Therefore, the efficiency of this Enhanced Oil Recovery technique in this type of field relies on viscosity reduction, miscible displacement and wettability alteration rather than IFT reduction.

Timing and magnitude of Southern Ocean sea ice/carbon cycle feedbacks

The Southern Ocean (SO) played a prominent role in the exchange of carbon between ocean and atmosphere on glacial timescales through its regulation of deep ocean ventilation. Previous studies indicated that SO sea ice could dynamically link several processes of carbon sequestration, but these studies relied on models with simplified ocean and sea ice dynamics or snapshot simulations with general circulation models. Here, we use a transient run of an intermediate complexity climate model, covering the past eight glacial cycles, to investigate the orbital-scale dynamics of deep ocean ventilation changes due to SO sea ice. Cold climates increase sea ice cover, sea ice export, and Antarctic Bottom Water formation, which are accompanied by increased SO upwelling, stronger poleward export of Circumpolar Deep Water, and a reduction of the atmospheric exposure time of surface waters by a factor of 10. Moreover, increased brine formation around Antarctica enhances deep ocean stratification, which could act to decrease vertical mixing by a factor of four compared with the current climate. Sensitivity tests with a steady-state carbon cycle model indicate that the two mechanisms combined can reduce atmospheric carbon by 40 ppm, with ocean stratification acting early within a glacial cycle to amplify the carbon cycle response.

Mars: Quantitative Evaluation of Crocus Melting behind Boulders

Abstract The possibility of liquid water on present-day Mars has been debated for half a century. Melting is physically difficult under Martian environmental conditions, because with the total pressure of the atmosphere near the triple point pressure of water, evaporative cooling of ice is high near the melting point. Here, a suite of quantitative models is used to investigate whether melting of seasonal water frost can occur on present-day Mars. An updated and generalized parameterization is derived for the turbulent convective heat flux that results from the buoyancy of water vapor. A three-dimensional surface energy balance model is used to calculate surface temperatures; it includes terrain shadowing, self heating, and subsurface conduction. Protruding topography creates locations that experience a rapid transition from conditions where water frost accumulates to high solar energy input. Beyond the pole-facing side of a boulder, CO2 and frost can accumulate seasonally, and once the Sun reemerges and the CO2 frost disappears, the water frost is heated to near melting temperature within one or two sols. Dust contained in the CO2 frost facilitates the formation of a protective sublimation lag. Temperatures within about 10 K of the melting point are reached within one or two sols after the end of water frost accumulation. For expected sublimation lag thicknesses, evaporative cooling is not significantly reduced. Overall, melting of pure water ice is not expected under present-day Mars conditions. However, at temperatures that are readily reached, seasonal water frost can melt on a salt-rich substrate. Hence, crocus melting behind boulders can lead to the formation of brines under present-day Mars conditions.

Zeta potential in intact carbonates at reservoir conditions and its impact on oil recovery during controlled salinity waterflooding

It is well known that oil recovery from carbonate reservoirs can be increased by modifying the injected brine composition in a process ‘controlled salinity water-flooding’ (CSW). However, the mineral- to pore- scale processes responsible for improved oil recovery (IOR) during CSW remain ambiguous and there is no method to predict the optimum CSW composition for a given crude-oil-brine rock system. Here we report the first integrated experimental measurements of zeta potential and IOR during CSW obtained at reservoir conditions. The zeta potential is a measure of the electrical potential at mineral-brine and oil-brine interfaces and controls the electrostatic forces acting between these interfaces.We find that the measured zeta potential in clean samples saturated with formation brine is typically positive and becomes more negative with brine dilution irrespective of temperature. After aging and wettability alteration, the zeta potential changes and we suggest a more positive zeta potential indicates a positive zeta potential at the oil-brine interface and vice-versa. Injecting low salinity brine yields IOR when the oil-brine zeta potential is identified to be negative, but no response when it is identified to be positive, consistent with the hypothesis that IOR during CSW is caused by an increase in the repulsive electrostatic force acting between mineral-brine and oil-brine interfaces. We suggest that the optimum brine composition for IOR during CSW should be chosen to yield the largest change in zeta potential at the mineral-brine interface with opposing polarity to the oil-brine interface and can be determined using the experimental method reported here.

Impact of mineral composition and distribution on the mechanical properties of porous media

Geological sequestration of CO2 in deep saline formations is a promising means of reducing atmospheric CO2 emissions. Once injected, CO2 dissolves into formation brine, lowering pH and creating conditions favorable for mineral dissolution. Cations released from dissolving minerals may create conditions favorable for secondary mineral precipitation, which can result in the long-term mineralogical trapping of injected CO2. These reactions may alter the natural rock mechanical properties, which can affect the safety and efficiency of geological sequestration. This work aims to investigate the impact of mineral composition and distribution on the mechanical properties of porous media. In this study, the mineralogy, mineral distribution, and mechanical properties of samples from Escambia County, AL, are evaluated. The mechanical properties of the rock samples are evaluated using the unconfined compression and indirect tensile tests in the combination with digital image correlation. The mineral composition and distribution are determined through the analysis of scanning electron microscopy backscattered electron and energy dispersive X-ray spectroscopy images of thin sections. These analyses showed that the mechanical properties vary with composition, which may have significant practical consequences for geological sequestration of CO2.

Fluids in High-Pressure Granulites

Properties of fluids in high-pressure granulites were studied in HP granulites (~8.7–11 kbar, ~800–900°С) and syngranulite fluid infiltration-driven HP metasomatites (~11–9 kbar, ~920–850°С) from the Lapland granulite belt of the Fennoscandian Shield. The study involved large-scale mapping of the rocks, microthermometry of mineral-hosted fluid inclusions, multiequilibrium mineral thermobarometry, and calculations of H2O activity based on mineral equilibria. The mafic pyroxene granulites and syngranulite metasomatites (quartz blastomylonites with orthopyroxene, sillimanite, and garnet; veins and vein-like bodies of orthopyroxene–garnet and diopside–scapolite rocks) contain similar assemblages of syngenetic fluid inclusions (which are hosted mostly in quartz and also in garnet, orthopyroxene, and scapolite) of contrasting chemical composition: nearly pure СО2 (distinctly predominant), brines (the dominant salts are CaCl2 and NaCl), and N2 ± H2O. These three types of inclusions coexist in the same generations of early inclusions: rarer primary (p) and predominant primary–secondary (ps). The CO2 inclusions have either high or low densities, and the N2 inclusions are of low density. The brine inclusions show a wide range of total salt contents (up to 30–35 wt%) and variable concentration proportions of the dominant salts: p-inclusions with a salinity of 20 wt% CaCl2 + 10 wt% NaCl; ps-inclusions with a salinity of 5 wt% CaCl2 + 20 wt% NaCl; p- and ps-inclusions with a salinity of 5–23 wt% NaCl eq; and p-inclusions with halite (up to 35 wt% NaCl). In general, CaCl2 is the predominant salt component in the early p- and ps-inclusions of the rocks. Considered together, currently available data (including Sr, Nd, and O isotope systems) on these rocks indicate that the external fluid flow during the origin of granulites was evidently of mantle origin. At the peak P–T parameters, the inclusions were entrapped from a heterogeneous fluid in which immiscible water–salt and CO2-rich fluids, which initially contained N2, coexisted. Data on the chemical composition and salt concentrations of the fluids, $${{a}_{{{{{\text{H}}}_{2}}{\text{O}}}}}$$ = 0.40–0.51, are compared with the theoretically predicted phase state of the fluids and the properties of the coexisting immiscible fluid phases at the estimated P–T parameters of granulite petrogenesis on the basis of numerical models in the H2O–CO2–NaCl and H2O–CO2–CaCl2 ternary systems. The location of the tie-lines and solvus were calculated to subsequently use for the thermodynamic prediction. The paper discusses similarity and the reasons for the difference between the theoretical compositions of the generated fluid phases and the composition of fluid inclusions, geochemical consequences of the heterogenization of granulite fluids (the formation of concentrated alkaline brines and a potentially acidic CO2-rich fluid phase, the values of the mass and volume fractions of these phases depending on variations in the composition of the initial homogeneous fluid, etc.). It follows that an extensive region of the compositions of aqueous fluids with different concentrations of CO2 and Na and Ca chlorides exists at the P–T parameters of HP granulites in which originally homogeneous fluid splits into compositionally contrasting fluid phases with different properties. This region of coexisting immiscible fluids significantly expands with increasing CaCl2 concentration. Hence, the lower crust at the level of the HP granulite facies may be the region where high-temperature immiscible fluids are generated. One of these fluids is a denser phase of alkaline brines, and the other is a less dense potentially acidic phase of H2O–CO2 fluids rich in CO2. Ascending along regional permeable zones, these fluid phases of deep origin can play an important role in magmatic, metamorphic, metasomatic, and ore-forming processes in the middle and upper crust.

Modeling the Kinetics of Saline Minerals Dissolution in Dombrovsky Quarry at the Kalush-Golinsky Potassium Salts Deposit

The article deals with the peculiarities of the chemical composition formation of brines in the Dombrovsky quarry, primarily due to the dissolution of potash ore minerals and host rocks in water coming from the pebble horizon and atmospheric precipitation. The solubility of the ore body minerals has been studied, and it ranges from 333 to 502 g∙dm–3. The boundary conditions for the formation of a saturated salt solution were determined. The estimated concentration of saturated potash ore solution under normal conditions is 426 g∙dm–3. The mechanism of dissolution is considered from the standpoint of D.I. Mendeleev's chemical theory of solutions. The temporary dynamics of minerals dissolution of the ore body is studied experimentally. The parameters of kinetic-diffusion process are calculated. The rate of the dissolution process, which occurs in the kinetic region, significantly exceeds the rate of concentration diffusion of hydrated ions: from 5 to 400 times depending on the mineral composition of salts. Theoretically from the point of view of multistage process kinetics and experimentally in laboratory conditions it is proved that the process that determines the formation of the chemical composition of brines (the slowest stage) is the concentration diffusion of hydrated ions Na+, K+, Cl–. They enter the liquid phase due to the minerals dissolution of the ore body and host rocks of soil and sides of the quarry, in the direction of overcoming the concentration difference - from the lower layers of the brine to its surface. This conclusion is confirmed by the ratio of weight coefficients а1 and а2. The contribution of the process of the main minerals dissolution of the ore body to the chemical composition formation of the solution is significantly less than the concentration diffusion process.

Flow behavior and thermal resistance of xanthan gum in formate brine

Drilling and completion operations in HP/HT environments demand the use of environmentally friendly fluids with suitable properties such as solid-free high-density and pseudoplastic behavior. Xanthan gum solutions in different brines may be an interesting alternative to ensure a suitable thermo-rheological behavior and biodegradability. Nevertheless, xanthan exposed at high temperature experiences thermal degradation that can modify the flow properties over time and limits the ceiling temperature of oilfield applications. To gain insight on this issue, this paper characterizes the flow behavior of low concentration XT solutions in calcium and potassium brines, evaluating the effect that potassium formate exerts on both the flow properties and the resistance to thermal degradation of xanthan solutions as a function of the biopolymer concentration. Xanthan in formate brine retains the pseudoplastic behavior up to 190 °C, however, low concentrate solutions undergo a thermal degradation that decreases the recovery of pseudoplasticity after being exposed to high temperature.

Testing the efficacy of active pressure management as a tool to mitigate induced seismicity

Manipulation of subsurface stresses through fluid injection/extraction may induce seismicity through modulation of overpressure along faults. Globally, most industrial operations do not induce significant earthquakes. However, the possibility of inducing moderate to large earthquakes is recognized as a significant risk for basin-scale carbon dioxide (CO2) storage operations (Niass et al., 2017). One possible method to reduce the occurrence of induced seismicity is to maintain only small (or zero) fluid overpressure changes in the subsurface through extraction of formation brine. For active pressure management (APM), operators may employ different procedures including extraction of various brine volumes and different configurations of injection/extraction well locations. However, the impact each these operational procedures on induced seismicity must be understood in order to develop management strategies.Here, we describe a numerical modeling workflow to evaluate the efficacy of APM techniques, that when applied to a specific site may be used to inform operational management strategies. We couple the multiphase reservoir model, NUFT, with the earthquake simulator, RSQSim and simulate seismicity induced by CO2 injection into a hypothetical brine saturated reservoir. Reservoir overpressure is modified by co-extraction of brine at various fractions of the injected CO2 volume from five potential wells. Our goal is to understand how the well-pair configuration and the extracted brine volume impact the total number and the maximum event magnitude. Additionally, the performance of each scenario is also evaluated in terms of the volume of CO2 that can be stored before an earthquake above a tolerance threshold is induced.

Optimisation of Smart Water to Enhance Oil Recovery Efficiency in a Part of Oil Field of Upper Assam Basin, India

Researchers have proved the significance of water injection by tuning its composition and salinity into the reservoir during smart water flooding. Once the smart water invades through the pore spaces, it destabilises crude oil-brine-rock (COBR) that leads to change in wettability of the reservoir rocks. During hydrocarbon accumulation and migration, polar organic compounds were being adsorbed on the rock surface making the reservoir oil/mixed wet in nature. Upon invasion of smart water, due to detachment of polar compounds from the rock surfaces, the wettability changes from oil/mixed wet to water wet thus enhances the oil recovery efficiency. The objective of this paper is to find optimum salinity and ionic composition of the synthetic brines at which maximum oil recovery would be observed. Three core flood studies have been conducted in the laboratory to investigate the effect of pH, composition and salinity of the injected brine over oil recovery. Every time, flooding has been conducted at reservoir formation brine salinity i.e at 1400 ppm followed by different salinities. Here, tertiary mode of flooding has been carried out for two core samples while secondary flooding for one. Results showed maximum oil recovery by 40.12% of original oil in place (OOIP) at 1050ppm brine salinity at secondary mode of flooding. So, optimized smart water has been proposed with 03 major salts, KCl, MgCl2 and CaCl2 in secondary mode of flooding that showed maximum oil recovery in terms of original oil in place.

Origin of blocky aragonite cement in Cenozoic glaciomarine sediments, McMurdo Sound, Antarctica

AbstractInorganic aragonite occurs in a wide spectrum of depositional environments and its precipitation is controlled by complex physio‐chemical factors. This study investigates diagenetic conditions that led to aragonite cement precipitation in Cenozoic glaciomarine deposits of McMurdo Sound, Antarctica. A total of 42 sandstones that host intergranular cement were collected from the CIROS‐1 core, located proximal to the terminus of Ferrar Glacier. Standard petrography, Raman spectroscopy and electron microprobe analysis reveal a prominent aragonite cement phase that occurs as a pore‐filling blocky fabric throughout the core. Oxygen isotope compositions (δ18O = −30·0 to −8·6‰ Vienna Pee‐Dee Belemnite) and clumped isotope temperatures (TΔ47 = 13·1 to 31·5°C) determined from the aragonite cements provide precise constraints on isotopic compositions (δ18Ow) of the parent fluid, which mostly range from −10·8 to −7·2‰ Vienna Standard Mean Ocean Water. The fluid δ18Ow values are consistent with those of pore water, previously identified as cryogenic brine in the nearby AND‐2A core. Petrographic and geochemical data suggest that aragonite cement in the CIROS‐1 core precipitated from a similar brine. The brine likely formed and infiltrated sediments in flooded glacial valleys along the western margin of McMurdo Sound during the middle Miocene Climatic Transition, and subsequently flowed basinward in the subsurface. Consequently, the brine forms as a longstanding subsurface fluid that has saturated Cenozoic sediments below southern McMurdo Sound since at least the middle Miocene. Aragonite cementation in the CIROS‐1 core is interpreted to reflect its proximal position to sites of brine formation and greater likelihood of experiencing brines with sustained high carbonate saturation states and Mg/Ca ratios. This unusual occurrence expands the range of known natural occurrences of aragonite cement. Given the potential for cryogenic brine formation in glaciomarine settings, blocky aragonite, as the end member of the spectrum of aragonite cement morphology, may be more widespread in glaciomarine sediments than currently thought.

Amino Acid as a Novel Wettability Modifier for Enhanced Waterflooding in Carbonate Reservoirs

SummaryReservoir wettability plays an important role in waterflooding, especially in fractured carbonate reservoirs since oil recovery from the rock matrix is inefficient because of their mixed wettability. This paper presents the first investigation of amino acids as wettability modifiers that increase waterflooding oil recovery in carbonate reservoirs.All experiments used a heavy-oil sample taken from a carbonate reservoir. Two amino acids were tested, glycine and β-alanine. Contact angle experiments with oil-aged calcite were conducted at room temperature with deionized (DI) water, and then at 368 K with three saline solutions: 243 571-mg/L salinity formation brine (FB), 68 975-mg/L salinity injection brine 1 (IB1), and 6898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB1.The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, in comparison to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the β-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.Glycine was further studied in spontaneous and forced imbibition experiments with oil-aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. The primary mechanism is that the glycine solution weakens the interaction between polar oil components and positively charged rock surfaces when the solution pH is between glycine's isoelectric point (pI) and the surface's point of zero charge (pzc). The secondary mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.The amino acids tested in this research are nontoxic and commercially available at relatively low cost. The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pI, solution's pH, and rock's pzc.

Low tension gas flooding for secondary oil recovery in low-permeability, high-salinity reservoirs

Low Tension Gas (LTG) flooding has been established as a successful tertiary oil recovery method for low-permeability carbonate reservoirs with high salinity and hard formation brine (~200,000 ppm and hardness 19,000 ppm). LTG flooding recovers oil using two integral mechanisms: ultra-low interfacial tension (IFT) between oil and water, and mobility control using in-situ foam generated by injected gas. In the present work, the scope of applicability of LTG flooding has been extended to secondary oil recovery under the same reservoir conditions. Secondary recovery using LTG flooding has been compared to conventional secondary recovery methods such as waterflooding. Oil recovery was observed to increase by 16% OOIP (Original Oil in Place) as compared to waterflooding, even in case of micellar flooding without gas. On introducing mobility control during LTG flooding in the form of injected gas, the secondary oil recovery was observed to increase steadily up to 81% OOIP. Co-injecting gas and surfactant also exhibited lower pressure drop than waterflood, thus underlining the importance and efficiency of mobility control using foam in secondary recovery. Gas injection strategy was improved in terms of injected foam quality and onset of gas injection. When gas was injected only during drive, ultimate oil recovery was reduced to 70% OOIP. Chemical injection strategy was also modified to test the impact of different in-situ salinity profiles on oil recovery.

Barium Sulfate Scaling and Control during Polymer, Surfactant, and Surfactant/Polymer Flooding

SummaryBarium sulfate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing waterflooding. Chemical enhanced oil recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulfate coproduction behavior, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer, surfactant, and surfactant/polymer (SP) flooding cEOR processes. To aid the cEOR economic decision, assessment of the impact of cEOR flooding type on both scale management and oil recovery is performed.Reservoir simulation has been used in this study, employing homogenous and heterogeneous two-dimensional (2D) areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of anionic surfactant and partially hydrolyzed polyacrylamide (HPAM) polymer [e.g., oil/water interfacial tension (IFT), IFT, polymer viscosity, and SP adsorption]. Assessment is made of the minimum inhibitor concentration (MIC) required to control the scale that is predicted to occur due to the changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor (SI) during squeeze treatments in the production wells is modeled.The high viscosity and more stable HPAM polymer slug reduces the mixing between the injected and the formation brines, especially with low-salinity low-sulfate (SO42−) make-up brine, reducing BaSO4 scale precipitation in the formation, delaying and reducing the potential scale risk in the producer wellbore compared to normal waterflooding. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion (ME) phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the waterflooding case, depending on the IFT, ME phase type, the injected salinity, and sulfate concentration. In SP flooding, low-salinity make-up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the injection brine salinity, SO42− concentration, and changing brine composition due to ion reactions affects the produced water rates, the number of required squeeze treatments and MIC values over time. This, then, impacts the inhibitor retention and release, which influences the treatment volumes and cost required to control scale over field life. Considering the economic impact of cEOR flood type on both oil recovery and scale management, low-salinity SP flooding is demonstrated to be the most viable option, showing the highest positive net present value (NPV).The study shows that barium and sulfate coproduction and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities) on the oil/water IFT, on the level of chemical adsorption, and on the selected brine salinity. The severity of the scale risk is also impacted by the flood techniques used, with the extent of reservoir reactions having an effect on the MIC required to control scale and the squeeze treatment volumes required to maintain production after breakthrough.

Application of a Zwitterionic Hydrophobic Associating Polymer with High Salt and Heat Tolerance in Brine-Based Fracturing Fluid.

ZID16PM, a zwitterionic hydrophobic associating polymer, has equivalent positive and negative charges and some hydrophobic monomers with twin-tailed long hydrophobic chains. It exhibits a great heat resistance and salt tolerance to the common salt in formation brine (MgCl2, CaCl2, NaCl, and KCl), which is attributed to its anti-polyelectrolyte effect and strong association force. High-salinity water (seawater or formation water) can be prepared as a fracturing fluid directly. In this paper, the formation water of the West Sichuan Gas Field is directly prepared into fracturing fluid with a concentration of 0.3% ZID16PM (Fluid-1), and the seawater of the Gulf of Mexico is directly prepared into fracturing fluid with a concentration of 0.3% ZID16PM (Fluid-2). Finally, rheological measurements, proppant suspension tests, and core matrix permeability damage rate tests for the Fluid-1 and Fluid-2 are conducted. Results show that after 120 min of shearing at 140 and 160 °C, respectively, the viscosity of Fluid-1 remains in the range of 50–85 mPa·s, and the viscosity of Fluid-2 remains in the range of 60–95 mPa·s. And the wastewater produced by an oilfield in Shaanxi, Xinjiang, and Jiangsu are also prepared into fracturing fluids with a concentration of 0.3% ZID16PM, the viscosity of these fracturing fluids can remain 32, 42, and 45 mPa·s, respectively, after 120 min of shearing at 160 °C. All results demonstrate that the polymer ZID16PM displays prominent performance in fracturing fluids.

Sources and Distribution of Fresh Water Around Cape Farewell in 2014

AbstractWe investigate the origin of fresh water on the shelves near Cape Farewell (south Greenland) using sections of three hydrographic cruises in May (HUD2014007) and June 2014 (JR302 and Geovide). We partition the fresh water between meteoric water sources and sea ice melt or brine formation using the δ18O of sea water. The sections illustrate the presence of the East Greenland Coastal Current (EGCC) close to shore east of Cape Farewell. West of Cape Farewell, it partially joins the shelf break, with a weaker near‐surface remnant of the EGCC observed on the shelf southwest and west of Cape Farewell. The EGCC traps the freshest waters close to Greenland and carries a brine signature below 50‐m depth. The cruises illustrate a strong increase in meteoric water of the shelf upper layer (by more than a factor 2) between early May and late June, likely to result from East and South Greenland spring melt. There was also a contribution of sea ice melt near the surface but with large variability both spatially and also between the two June cruises. Furthermore, gradients in the freshwater distribution and its contributions are larger east of Cape Farewell than west of Cape Farewell, which is related to the EGCC being more intense and closer to the coast east of Cape Farewell than west of it. Large temporal variability in the currents is found between different sections to the east and southeast of Cape Farewell, likely related to changes in wind conditions.

Experimental investigation of assessment of the contribution of heterogeneous semi-confining shale layers on mixing and trapping of dissolved CO2 in deep geologic formations

In most conceptual models of dissolution trapping of CO2, it is assumed that mixing of dissolved supercritical CO2 and formation brine occurs through density-driven convection. In our previous modeling study, we showed that the presence of continuous low-permeability shale layers in the formations causes convective shutdown through disruption of fingers, which impacts the effectiveness of mixing and trapping processes. However, these layers are naturally heterogeneous due to variations in compositional and textural properties. In the present study, we investigate the potential effects of heterogeneity present within semi-confining low-permeability layers on the overall mixing and trapping of dissolved CO2. Since accurate field experimentation in deep geologic formations is difficult due to inability to adequately characterize geology and define boundary conditions of the formation, we designed well-controlled experiments using NaBr solution and water under laboratory conditions. We conducted intermediate-scale 3D laboratory experiments under two homogeneous and one heterogeneous multilayered sand packing configurations. The results of these experiments show that connectivity of relatively higher permeability material within the semi-confining low-permeability layers contributes to mixing through (1) brine leakage between upper and lower aquifers (reverse convection), and (2) trapping through diffusion and back diffusion of initially trapped mass due to reversed concentration gradients in the long term. These findings suggest that when estimating the effectiveness of dissolution trapping in CO2 sequestration one needs to consider possible deviations from the traditional convective mixing theory in homogeneous media. Under some conditions of natural formation heterogeneity, diffusion can contribute to trapping; in some others, it may not.

CO2 storage in the Paluxy formation at the Kemper County CO2 storage complex: Pore network properties and simulated reactive permeability evolution

The Paluxy formation is being considered as a prospective CO2 reservoir at the Kemper County CO2 Storage Complex. Here, the pore and pore-throat size distributions and connectivity of the Paluxy formation is evaluated through analysis of 3D X-ray Computed Tomography images. In spite of resolution limitations that constrain the pore-throat sizes detectable by imaging, the permeability contributing pore-throats are successfully characterized through 3D imaging analysis. Image-obtained pore and pore-throat size distributions and pore connectivity are then utilized to construct pore network models and simulate permeability. After CO2 is injected, it will dissolve into formation brine and create conditions favorable for dissolution of primary minerals and precipitation of secondary minerals. These reactions will alter the porosity and permeability of the system to varying degrees depending on the spatial location of reactions. Here, the possible porosity-permeability evolution is simulated using pore network models considering mineral reactions occurring uniformly and non-uniformly throughout the network. For a given change in porosity, there is a large range of possible permeability outcomes. Depending on the extent and spatial location of mineral reactions, permeability may decrease by more than one order of magnitude as minerals precipitate. During dissolution, simulated permeability increases as much as 500%.

Beyond Carbon Steel: Detecting Wellbore Shape and Cavities, and Cement Imperfections in Cased Wells

The non-corrosive, electrically resistive fiberglass casing materials may improve the economics of oil and gas field projects. At moderate temperatures (<120 °C), fiberglass casing is superior to carbon steel casing in applications that involve wet CO2 injection and/or production, such as carbon capture and storage, and CO2-based enhanced oil recovery (EOR) methods. Without a perfect protective cement shell, carbon steel casing in contact with a concentrated formation brine corrodes and the fiberglass casing is superior again. Fiberglass casing enables electromagnetic logging for exploration and reservoir monitoring, but it requires the development of new logging methods. Here we present a technique for the detection of integrity of magnetic cement behind resistive fiberglass casing. We demonstrate that an optimized induction logging tool can detect small changes in the magnetic permeability of cement through a non-conductive casing in a vertical (or horizontal) well. We determine both the integrity and solidification state of the cement-filled annulus behind the casing. Changes in magnetic permeability influence mostly the real part of the vertical component of the magnetic field. The signal amplitude is more sensitive to a change in the magnetic properties of the cement, rather than the signal phase. Our simulations showed that optimum separation between the transmitter and receiver coils ranged from 0.25 to 0.6 m, and the most suitable magnetic field frequencies varied from 0.1 to 10 kHz. A high-frequency induction probe operating at 200 MHz can measure the degree of solidification of cement. The proposed method can detect borehole cracks filled with cement, incomplete lift of cement, casing eccentricity, and other borehole inhomogeneities.

Relative Humidity on Mars: New Results From the Phoenix TECP Sensor.

In situ measurements of relative humidity (RH) on Mars have only been performed by the Phoenix (PHX) and Mars Science Laboratory (MSL) missions. Here we present results of our recalibration of the PHX thermal and electrical conductivity probe (TECP) RH sensor. This recalibration was conducted using a TECP engineering model subjected to the full range of environmental conditions at the PHX landing site in the Michigan Mars Environmental Chamber. The experiments focused on the warmest and driest conditions (daytime) because they were not covered in the original calibration (Zent et al., 2010, https://doi.org/10.1029/2009JE003420) and previous recalibration (Zent et al., 2016, https://doi.org/10.1002/2015JE004933). In nighttime conditions, our results are in excellent agreement with the previous 2016 recalibration, while in daytime conditions, our results show larger water vapor pressure values. We obtain vapor pressure values in the range ~0.005–1.4 Pa, while Zent et al. (2016, https://doi.org/10.1002/2015JE004933) obtain values in the range ~0.004–0.4 Pa. Our higher daytime values are in better agreement with independent estimates from the ground by the PHX Surface Stereo Imager instrument and from orbit by Compact Reconnaissance Imaging Spectrometer for Mars. Our results imply larger day‐to‐night ratios of water vapor pressure at PHX compared to MSL, suggesting a stronger atmosphere‐regolith interchange in the Martian arctic than at lower latitudes. Further, they indicate that brine formation at the PHX landing site via deliquescence can be achieved only temporarily between midnight and 6 a.m. on a few sols. The results from our recalibration are important because they shed light on the near‐surface humidity environment on Mars.