Formation Water Salinity Research Articles

A combined geochemical and μCT study on the CO2 reactivity of Surat Basin reservoir and cap-rock cores: Porosity changes, mineral dissolution and fines migration

Geological storage of CO2 generally involves injection of a CO2 stream into a high porosity and permeability reservoir, contained by one or more overlying low permeability formations. Sandstone reservoirs and associated cap-rocks of targeted CO2 storage sites therefore have distinct properties such as porosity and mineral contents. Their geochemical response or reactivity to injected supercritical CO2 and associated changes in porosity, and permeability affecting scaling, mineral trapping, injectivity, or migration can therefore be very different. Six drill core samples including quartz-rich sandstones, calcite cemented sandstones, and feldspar or clay-rich cap-rocks from a proposed demonstration site in the Surat Basin, Australia, were characterized before and after reaction with pure supercritical CO2 and low salinity formation water. The quartz-rich sandstones have low reactivity, and maintain high porosities with visible pore connectivity after reaction, they are unlikely to be affected by scaling. Kaolin and fine grain movement observed via μCT and SEM could have the potential to open or plug pores, potentially increasing or decreasing permeability and CO2 injectivity. Calcite cemented sandstones had the greatest measured change in porosity after reaction via calcite dissolution. Narrow angular channels were formed in the calcite cement around framework grains, extending through to the center of the sub-plug in the courser grained rock, and surface roughness increased. Solution pH was however quickly passivated. The highest concentrations of Ca, Mn, Sr, and Mg were released to solution from calcite dissolution. Clay (and feldspar) rich cap-rock core had mainly microporosity and the smallest initial pore throat diameters associated with clays. Small changes to μCT calculated porosities after reaction were related to a decrease in chlorite X-ray density, and dissolution of patchy carbonate minerals. Pores were disconnected in μCT images, except for some created horizontal connection along a sandy lamination in a cap-rock. Dissolved concentrations of Ca, Fe, Si, Sr, Mn, Li and Mg increased via dissolution of both carbonate and silicate minerals. Dissolved Ca, Fe, Mn and Mg from silicate minerals in the cap-rock were available for longer term mineral trapping of CO2. Potential increases in porosity and migration will be highest in the calcite cemented zones, while clay-rich cap-rocks could be expected to maintain integrity. There is a low likelihood of mineral trapping or scaling in the quartz rich lower Precipice Sandstone. Overlying rocks can provide Fe, Mg, Ca for mineral trapping of CO2 as ferroan carbonates such as siderite, ankerite and dolomite over longer time scales when pH is buffered.Changes to porosity, mineral content, and water chemistry after pure CO2 reaction observed here and in other published studies were dependent on mineral content and fluid accessibility. These results could be generalized to other sandstone reservoirs where it is expected to inject CO2. The results can also be used to validate geochemical models to build longer term predictions.

Insights into the role of clays in low salinity water flooding in sand columns

Clays in sandstone are thought to be a key factor in low salinity (LS) water flooding. This study investigates the effects of quartz, kaolinite and illite in LS water flooding in synthetic sand columns as a function of temperature. Four chromatography columns containing different amounts of pure quartz sand, illite, and kaolinite (100% quartz sand; 95/5% sand/illite; 95/5 sand/kaolinite; and 95/2.5/2.5% sand/illite/kaolinite). The use of these synthetic columns gives full control over mineralogy. These columns were saturated with high salinity (HS) formation water with 0.01 M (M) sodium acetate and aged for a week at 70 °C. They were then flooded with waters (yes, the use of water to displace water) with various salinities at four different temperatures (25, 70, 90 and 120 °C). Effluent concentrations of Ca2+ and acetate (CH3COO−) and pH were measured. This is a novel experimental design, where formation water containing sodium acetate is flooded with waters of varying salinity to gain insight into LS flood performance and possible recovery mechanisms. The hypothesis pursued here is that the behavior of the acetate ion (attached to matrix minerals during the aging process and then released due to ionic exchange) in an LS flood would provide a valuable analog that would simulate the bonding of carboxylic acids in crude oils with reservoir matrix minerals (and subsequent desorption during LS flooding). Key results include the following: (a) Our hypothesis was correct—the use of Na acetate behaved analogously to carboxylic acid, giving useful insights; (b) The quartz-only column showed strong evidence (elevated pH, presence of Ca2+ and acetate in effluent) of ionic exchange due to LS flooding, showing that pure quartz is responsive to LS flooding and that clays are not absolutely needed; (c) Quartz plus kaolinite plus illite gave a slightly higher response than pure quartz so clays can play a role. Oil displacement results were also done for a pure quartz sand column, and this showed a strong response to the LS flood, confirming that clays are not absolutely needed.

Origin of Flowback and Produced Waters from Sichuan Basin, China.

Shale gas extraction through hydraulic fracturing and horizontal drilling is increasing in China, particularly in Sichuan Basin. Production of unconventional shale gas with minimal environmental effects requires adequate management of wastewater from flowback and produced water (FP water) that is coextracted with natural gas. Here we present, for the first time, inorganic chemistry and multiple isotope (oxygen, hydrogen, boron, strontium, radium) data for FP water from 13 shale gas wells from theLower Silurian Longmaxi Formation in the Weiyuan gas field, as well as produced waters from 35 conventional gas wells from underlying (Sinian, Cambrian) and overlying (Permian, Triassic) formations in Sichuan Basin. The chemical and isotope data indicate that the formation waters in Sichuan Basin originated from relics of different stages of evaporated seawater modified by water-rock interactions. The FP water from shale gas wells derives from blending of injected hydraulic fracturing water and entrapped saline (Cl ∼ 50,000 mg/L) formation water. Variations in the chemistry, δ18O, δ11B, and 87Sr/86Sr of FP water over time indicate that the mixing between the two sources varies with time, with a contribution of 75% (first 6 months) to 20% (>year) of the injected hydraulic fracturing water in the blend that compose the FP water. Mass-balance calculation suggests that the returned hydraulic fracturing water consisted of 28-49% of the volume of the injected hydraulic fracturing water, about a year after the initial hydraulic fracturing. We show differential mobilization of Na, B, Sr, and Li from the shale rocks during early stages of operation, which resulted in higher Na/Cl, B/Cl, Li/Cl, and 87Sr/86Sr and lower δ11B of the FP water during early stages of FP water formation relative to the original saline formation water recorded in late stages FP water. This study provides a geochemical framework for characterization of formation waters from different geological strata, and thus the ability to distinguish between different sources of oil and gas wastewater in Sichuan Basin.

Salinity and Macrocomponent Composition of Pore Water of the Bazhenov, Achimov, and Georgiev Formations from Analysis of Aqueous Extracts

This paper presents a reliable dataset on formation water salinity (mineralization) and salt composition for low-permeable (tight) shale rocks of the Bazhenov, Achimov and Georgiev formations for the first time. The data were obtained via laboratory analysis of aqueous extracts from rock samples before and after hydrocarbon extraction (cleaning). Thermodynamic modeling of the obtained solutions with a number of minerals was carried out and a correlation analysis of the Na/Cl, Ca/SO4, Mg/SO4, Ca/Cl, Ca/HCO3, and Fe/SO4 ratios was performed. It was established that the concentrations of certain macro-components, including Ca, Mg, Fe, hydrocarbonate, and sulfate ion in pore water cannot be reliably determined using aqueous-extract data, while at the same time, a reliable estimate of the minimal formation water salinity could be made. The need to use non-extracted core samples with the maximum preserved residual water saturation to study a pore water composition of tight shale rocks is shown.

Formation water salinity and macro-components’ composition for Bazhenov, Achimov and Georgiev formations from the results of water extract analysis

The paper presents for the first time a reliable dataset on formation water salinity and salt composition for tight shale formations of Bazhenov, Achimov and Georgiev suites. The data were obtained in the result of laboratory analysis of aqueous extracts from rock samples before and after its hydrocarbon extraction (cleaning). Based on the experimental data a thermodynamic modeling of solution-mineral equilibrium was performed followed by Na/Cl, Ca/SO4, Mg/SO4, Ca/Cl, Ca/HCO3, Fe/SO4 correlation analysis. The results shown that concentrations of certain macro-components, including Ca, Mg, Fe, hydrocarbonate and sulfate ion in pore solutions cannot be reliably determined using aqueous extract data. At the same time a reliable estimate nominal salinity of formation water could be provided using the obtained data. The paper concludes that a reliable study of macro-components’ chemical composition in formation waters of tight shale formations requires laboratory analysis of non-extracted rock core samples with maximal preservation of water content.

Crude-Oil/Brine Interaction as a Recovery Mechanism for Low-Salinity Waterflooding of Carbonate Reservoirs

SummaryLow-salinity waterflooding in limestone formations has been less explored and hence less understood in enhanced-oil-recovery (EOR) literature. The mechanisms leading to improved recovery have been mostly attributed to wettability alteration, with less attention given to fluid/fluid-interaction mechanisms. In this work, we present a thorough investigation of the formation of water-in-oil microdispersions generated when low-salinity brine encounters crude oil and the suppressed snap-off effect caused by the presence of sulfate content in seawater-equivalent-salinity brines as recovery mechanisms in limestone rocks. We believe this is a mechanism that leads to the improved oil recovery experienced with low-salinity waterflooding and seawaterflooding in carbonate formations. This novel interpretation was studied by integrating petrographic and spectroscopic observations, dynamic interfacial-tension (IFT) measurements, thermogravimetrical analyses, and coreflooding techniques.Our data show that low-salinity brine caused a greater change in the crude-oil composition compared with seawater brine and formation-water brine. Formation-water brine created nearly no changes to the crude-oil composition, indicating its limited effect on the crude oil. These compositional changes in crude oil, caused by the low-salinity brine, were attributed to the formation of water-in-oil microdispersions within the crude-oil phase. Fourier-transform infrared (FTIR) spectroscopy data also showed that at brine-concentration levels greater than 8,200 ppm, this phenomenon was not experienced. Oil-production data for nonaged limestone cores showed an improved recovery of approximately 5 and 3% for seawater and low-salinity brines, respectively. Although the wettability-alteration effect was minimized by the use of nonaged cores, improved oil recovery was still evident. This was interpreted to represent the formation of water-in-oil microdispersions when low-salinity water (LSW) of 8,200-ppm salinity and less was used. The formation of the microdispersions is believed to increase the sweep efficiency of the waterflood by swelling and therefore blocking the pore throats, causing low-salinity-brine sweeping of the unswept pore spaces. Improved recovery by seawater brine was attributed to the changes in dynamic IFT measurement experienced using seawater brine as the continuous phase, compared with the use of LSW and formation-water-salinity (FWS) brine. This change caused a higher surface dilatational elasticity, which leads to a suppression of the snap-off effect in coreflooding experiments and hence causes improved oil recovery.Our studies conclude that the formation of microdispersions leads to improved oil recovery in low-salinity waterflooding of limestone rocks. Furthermore, the use of seawater as a displacing fluid succeeds in improving recovery because of its high surface elasticity suppressing the snap-off effect in the pore throat. We also present an easy and reliable mixing procedure representative of porous media, which could be used for screening brine and crude-oil samples for field application. Fluid/fluid interaction as well as high surface elasticity should be investigated as the causes of wettability alteration and improved recovery experienced by the use of LSW and seawater-salinity (SWS) brines interacting with limestone formations, respectively.

Experimental analysis to design optimum phase type and salinity gradient of Alkaline Surfactant Polymer flooding at low saline reservoir

This paper presents the experimental analysis to find the optimum alkaline-surfactant-polymer (ASP) formula and the effects of salinity gradient suitable for oil reservoirs with low salinity formation water. It has been challenging to obtain high oil recovery when the reservoir salinity is lower than the injection salinity of ASP formulation. This paper carried out phase behavior tests for 28 experiments with 22 kinds of surfactant and subsequent coreflooding for the optimum formula with pre-designed salinity gradient profiling for pre-flush, ASP slug, and polymer drive. The optimum ASP formula from the phase behavior study, i.e., 0.5 wt% Linear alkylbenzene sulfonate (LAS), 2 wt% Diethylene glycol butyl ether (DGBE), and 1 wt% Na2CO3, results in the optimum salinity of 2.8 wt% NaCl with 10 cc/cc solubilization ratio, and the middle phase type III microemulsion occurs in the range of 2.5–3.4 wt% NaCl. The oil recovery implementing this formula and negative salinity gradient, i.e. Winsor type II-III-I for coreflooding experiments are about 75.8% which is better than the other salinity gradients such as Winsor type I-II-I and I-III-I. Excluding high saline pre-flush, the salinity gradient consisted of Winsor type I-II-I and Winsor type I-III-I are able to recover the desirable amount of oil. The results could be applicable on designing the optimal ASP flooding at low salinity formation considering the formulation of surfactants and co-solvents, and the effects of salinity gradients.

Logging method for formation water salinity determination by PGNAA technology

A prompt gamma neutron activation analysis logging method for formation water salinity determination is proposed. The response of formation water salinity for capture gamma ray spectrum and thermal neutron counts ratio are studied by Monte Carlo simulation method. Formation porosity and borehole fluid salinity influence on formation water salinity is corrected. A synthetical logging case is simulated to indicate the effectiveness of this logging method. The new logging method is also applied in oil field, and the formation water salinity of different depth is calculated.

A method for evaluating gas saturation with pulsed neutron logging in cased holes

Tight gas reservoirs have been one of the most important field of gas exploration and development, and the dynamic monitoring of gas saturation is of great significance to the adjustment of oilfield development scheme. Pulsed neutron logging technology plays an important role in the evaluation of gas saturation in cased holes. The low porosity of tight gas reservoir presents a new challenge to the application of pulsed neutron logging technology. In order to further investigate the measurement information of pulsed neutron logs to improve the performance of gas saturation measurement, the Monte Carlo numerical simulation method is used to study the gas saturation responses of different parameters obtained by the pulsed neutron-gamma logging instrument with an extra gamma-ray detector added. The results show that the capture count ratio measured by the instrument is mainly affected by changes in the hydrogen index of the formation. The ratio of pure inelastic gamma rays is more sensitive to the variation of formation density. When the porosity of the reservoir is fixed, the gas layer has a low hydrogen index and low density relative to the water layer. By combining the response characteristics of the two ratios, a new gas saturation evaluation parameter (GSEP) is proposed to evaluate gas saturation. The new method displays a higher gas sensitivity compared with the conventional ratio method and macroscopic capture cross section (Sigma) method. In addition, the response characteristics of GSEP in different well logging environments are also studied. It displays GSEP is less affected by the variation of the formation water salinity and clay contents compared with the Sigma method. At last, field examples are presented to validate the effectiveness of the proposed method.

Petrophysical and aquifer parameters estimation using geophysical well logging and hydrogeological data, Wadi El-Assiuoti, Eastern Desert, Egypt

The study of groundwater potential in Wadi El-Assiuoti is of a prime importance for both current and future development. In this paper the groundwater occurrences are investigated using integrated; 1) geophysical well logging (Self potential, Resistivity and Gamma Ray), 2) subsurface lithologic data and 3) hydraulic data (transmissivity, transmissibility, hydraulic conductivity and storativity) in addition to reviewing all studies on Wadi El-Assiuoti. Different petrophysical parameters (formation water resistivity, formation factor, porosity, permeability, salinity and shale volume) are computed. These parameters are very necessary to identify the aquifers characteristics in the surveyed area. The integration between geophysical and hydrogeological data shows the possibility of two water bearing formation (Quaternary and Plio-Pleistocene). Generally, porosity and permeability values of these aquifers decrease toward the west. The aquifers exist under unconfined to semi confined conditions. The wide range values of both well efficiency and hydraulic conductivity indicate heterogeneity in the lithology and hydraulic characteristics of the aquifer materials. The computed transmissibility values indicate that the water-bearing sediments in the area under investigation are generally of high productivity. In some localities due to the heterogeneity of sediment, the water-bearing sediments are of moderate productivity. Recently, due to the increase of drilling activities at the middle part of the studied area some problems concerning the groundwater potential and high salinity in the area are happening.

Redox zonation and organic matter oxidation in palaeogroundwater of glacial origin from the Baltic Artesian Basin

Ordovician-Cambrian aquifer system (O-Cm) in the northern part of the Baltic Artesian Basin (BAB), Estonia, is part of a unique groundwater reservoir where groundwater originating from glacial meltwater recharge from the Scandinavian Ice Sheet is preserved. The distribution of redox zones in the anoxic O-Cm aquifer system is unusual. Strongly reducing conditions are found near the modern recharge area characterized by low concentrations of sulphate (<5 mg·L−1) and the presence of CH4 (up to 3.26 vol%). The concentrations of SO42− increase and concentrations of CH4 decrease farther down the groundwater flow path. Sulphate in fresh glacial palaeogroundwater originates probably from pyrite oxidation while brackish waters have gained their sulphate through mixing with relict saline formation waters residing in the deeper parts of the aquifer system. Stable isotopic composition of sulphate, especially relations between δ18OSO4-δ18Owater (∆18OSO4-H2O from +20.5 to +31.1‰) and δ34SSO4-δ34SH2S (∆34SSO4-H2S value of +47.9‰) support a widespread occurrence of bacterial sulphate reduction in fresh glacial palaeogroundwater. We propose, that the observed unusual redox zonation is a manifestation of two different flow systems in the O-Cm aquifer system: 1) the topographically driven flow system which drives the infiltration of waters through the overlying carbonate formation in the modern recharge area; 2) the relict flow system farther down the groundwater flow path which developed as a response to large hydraulic gradients imposed by the Scandinavian Ice Sheet in Pleistocene. Thus, the strongly reducing conditions surrounding the modern recharge area may show the extent to which post-glacial recharge has influenced the aquifer system. O-Cm aquifer system is an example of an aquifer that has not reached a near-equilibrium state with respect to present day flow conditions and still exhibits hydrogeochemical patterns established under the influence of a continental ice sheet in Pleistocene.

Quantifying the extent of flowback of hydraulic fracturing fluids using chemical and isotopic tracer approaches

Hydraulic fracturing technologies have facilitated the rapid development of shale gas and other unconventional hydrocarbon resources throughout the world. Following hydraulic fracturing operations, a large quantity of water flows back to the surface. Understanding the provenance and composition of this returned water is therefore of paramount importance in order to optimize the recycling and reuse of the millions of litres of wastewater generated by hydraulic fracturing and to reduce freshwater consumption. Here we report flowback and produced fluids data obtained from a horizontal well in a low permeability reservoir within the Montney formation in Alberta, Canada. The reservoir was fractured with a mixture of nitrogen and water and the returned water was sampled 24 times during the first week of flowback and once after more than one year of production. The samples were analyzed for concentrations of major ions and for the stable isotope composition of water. The TDS (total dissolved solids) of the samples increased rapidly from 395 mg/L for the injected water to 50,000 mg/L after two days and 96,000 mg/L at the end of the first week of flowback. At the same time, δ2H values increased from −142‰ to −113‰ and δ18O values increased from −18.3‰ to −9.8‰. After more than one year, TDS reached 204,000 mg/L while δ2H and δ18O values further increased to −68‰ and + 2.7‰. The salinity of the returned water is shown to be the result of the mixing between the highly saline formation water initially present in the reservoir before hydraulic fracturing, with the fresh water used for hydraulic fracturing. The presented mathematical model allows the calculation of the amount of fracturing fluid recovered as well as the quantity of saline formation water produced and reveals that most of the injected water is imbibed in the host rock of the producing formation. After a week of flowback, only 18% of the injected water had been recovered, while the recovery of fracturing fluids after 14.5 months is estimated at 36% of the total volume injected.

Conformance control for CO2-EOR in naturally fractured low permeability oil reservoirs

Poor sweep efficiency seriously limits field applications of CO2-EOR, especially in fractured reservoirs. The investigation of CO2 production performance and the method to control CO2 production becomes a key to successfully run a CO2-EOR project. In this study, artificial sandstone cores were used to perform a series of CO2 flooding experiments at reservoir conditions of pressure, temperature and formation water salinity. Injection pressure and rock heterogeneity were taken into account to study their effect on CO2 production performance. Two-stage gas channeling control with three different scenarios, including PLS gel and ethylenediamine, starch gel and ethylenediamine, and starch gel and CO2 foam, was presented to improve the conformance in 3-D fractured-core models. Based on production performance and experimental observation, three production stages were clearly stated, including gas-free production stage, oil/gas co-production stage, and gas channeling stage. Oil/gas co-production stage contributed the most to oil recovery. This finding was very consistent with the practical production performance of CO2 flooding in oil fields. The conformance improvement and the increase in injection pressure (within permissible range bearing in mind of fracturing pressure) could remarkably enhance the oil recovery at oil/gas co-production stage. In 3-D radial flow experiments, the two-stage gas channeling control presented great potential in delaying gas production and improving CO2 flooding efficiency. The combination of starch gel and ethylenediamine achieved the best result. The starch gel could effectively block the fracture, while the viscous reactant of ethylenediamine and in-situ CO2 within high permeability layer could successfully tune injected CO2 to flood low permeability layer. This study could help field engineers determine the optimal timing of CO2 production control, and also offered an optimal method to improve the conformance for CO2-EOR.

Investigating the effects of rock and fluid properties in Iranian carbonate matrix acidizing during pre-flush stage

Acidizing of carbonate oil-wet rocks saturated with oil and saline formation water is subjected failure in some cases due to acid-induced damage such as sludge and emulsion formations. This condition may also lead to mineral precipitation, oil film barrier between acid and rock and diversion chemical malfunctions. Therefore, pre-flush process has been proposed as one of the most efficient stage for oil-wells matrix acidizing to reduce these challenges significantly. Besides, the pre-flush stage would result in more clean rock as the reservoir fluids are pushed back from the near wellbore regions, restoring rock wettability to more water wet state, preventing direct acid-oil contact and cooling rock surface to control acid-rock reaction at high temperature reservoir.This laboratory work is designed to study the effectiveness of three different pre-flush fluids and assess their ability in reducing interfacial tension (IFT) to displace original reservoir fluids around the wellbore as well as changing the rock wettability to increase rock dissolution rate. The results showed that a 0.5%wt of C16TAB aqueous solution (cationic surfactant additive) has passed successfully the pre-flush optimization criteria which can be utilized as pre-flush fluid of the carbonate oil-wet acidizing. It was shown that the wettability and IFT were changed quickly as it is requested for the pre-flush stage. The contact angle was decreased from 172° to 33° in two hours period and the IFT was reduced from 8.9 to 0.62 (dyne/cm) at reservoir condition (P = 4000 psia, T = 85 °C).In addition, the dissolution rate of dolomite rock from an Iranian oil reservoir at three different states of oil-wet, water-wet and pre-flush treated with 15% HCl was measured and compared. The measured dissolution rate of initially water-wet rock was measured to be 1 × 10−4 mol/cm2.s which is the same as the dissolution rate measured for C16TAB treated oil wet rock. This confirms the suitable wettability alteration through C16TAB pre-flush.

Inversion and propagation of the Late Paleozoic Porjianghaizi fault (North Ordos Basin, China): Controls on sedimentation and gas accumulations

Abstract In contrast to typical intracratonic basins, the Ordos Basin comprises marginal deformation belts and complex fault systems. This study uses 3D seismic data tied to sonic and stratigraphic data from exploration wells, to document the geographic extend of the Porjianghaizi fault and its control on sedimentation and gas accumulation in the northern Ordos Basin. Our results show that the geometry of large Porjianghaizi fault is controlled by five small fault segments. The growth history of the Porjianghaizi fault composes four stages: (1) an initiation stage (Late Carboniferous to Early Permian); (2) a reactivation stage during the Late Triassic; (3) an inversion stage during the Middle Jurassic; and (4) an interaction and linkage stage during the Late Jurassic. Detailed studies show that the Porjianghaizi fault had significant control on sedimentation and gas accumulation. During the initiation stage (Late Carboniferous to Early Permian), five fault segments and associated relay ramps controlled the sedimentation in the study area. The relay ramps formed transport pathways in which sediment extended from north basin margin to the basin center. In contrast, sedimentation along the fault was more localized. Based on Shale Gouge Ratios (SGR) and formation water salinity, the fault sealing capacity of the Porjianghaizi fault is characterised by “horizontal segmentation”, which means the fault composes laterally sealed areas and laterally connected areas along the fault strike. As a corollary, we propose that gas resources were mainly generated from the south where there are thick source rocks, migrating vertically through interbedded open fractures first, and then laterally through the junction zone of fault (relay ramps). It eventually accumulated in structural traps found in the northern areas. Understanding the evolution of the Porjianghaizi fault is important for predicting the distribution of sedimentary facies in Upper Carboniferous and Lower Permian units. As well as understanding the migration and distribution of gas resources in the north Ordos Basin, these results can further help in hydrocarbon exploration in the north Ordos Basin.

Modelling the influence of interaction between injection and formation brine salinities on in-situ microbial enhanced oil recovery processes by coupling of multiple-ion exchange transport model with multiphase fluid flow and multi-species reactive transport models

Interaction between injection water (IW) and formation water (FW) salinities during microbial flooding critically influences the dynamics of in-situ Microbial Enhanced Oil Recovery (MEOR) processes. However, the lack in understanding of the influence of salinity interactions on MEOR processes had led to unreliable prediction of MEOR performance, and non-development of efficient strategies to improve the MEOR performance. Hence, analysing the influence of salinity interactions on MEOR processes would make the prediction of MEOR processes more realistic, and thereby, it could assist in development of suitable strategies to enhance the oil recovery. Thus, in the present study, a novel mathematical model has been developed by coupling the Multiple Ion (Na, Ca, Mg, Cl, SO4) Exchange (MIE) transport model with the MEOR model, and it has been solved numerically by finite volume technique. The MIE transport model simulates the resultant spatial and temporal salinity distribution within the reservoir due to the mixing of IW and FW salinities during microbial flooding. The MEOR model simulates the coupled multiphase fluid (water-oil) flow and multispecies (microbes-nutrients) reactive transport processes within the reservoir, and finally predicts the oil recovery due to microbial flooding. Subsequently, the influence of IW and FW at different salinities on MEOR processes has been investigated. The present numerical results were validated with the experimental and analytical results. The results clearly suggest that the in-situ FW salinity was completely altered to the externally injected IW salinity, and this IW salinity dictates the entire MEOR processes as against the conventionally assumed FW salinity. Further, it is revealed that lowering the IW salinity from 0.5M to 0.1M had recovered 4.5%–14% of Original Oil in Place (OOIP) higher than that of conventionally used IW (sea water) for microbial flooding. Moreover, the MEOR performance could be enhanced significantly in reservoirs with any initial FW salinity by adopting IW salinity closer to the salinity condition at which the microbial growth and biosurfactant production is maximum. Finally, the present work assists in the selection of suitable reservoir, microbes, and IW salinity for attaining maximum oil recovery by microbial flooding. Thus, the present work helps to enhance the performance of MEOR technique.

Characteristics of scale deposition in gas-condensate wells

Formulation of the problem. The article deals with one of many possible complications that may occur in the process of gas and gas-condensate wells operation. In fact, scale deposits can be observed in wells at all stages of field development. Scale deposition inside the tubing has a negative impact on hydrocarbons production. This causes the decline of gas production rate. The major factor of scale deposits formation is overtreatment of water solution with different salts and the effect of field hydrogeology. Thus, special methods are used in practice to prevent scale deposition and combat this complication.The purpose of the article. To define the causes of scale deposition, the detailed analysis of well operation should be performed that will help to take the appropriate prevention measures. Methods. The authors’ own achievements as well as the research results of domestic and foreign investigators made the methodical basis for the article.Results. The production data of the wells from different fields have provided the information about scale deposition. Many of the described ways of combating and eliminating scale deposits are expensive, their use causes well downtime and production decline. Therefore, it has been proposed to take easy-to-use preventive measures.Scientific novelty and practical significance. During investigation of the production researches results and calculations the specialists of UkrNDIgas proposed to classify the wells with reduced production capacities within the field into groups and categories according to the degree of total salinity of formation water. It has been proposed to control the process of scale deposition by the results of water analysis, taken from the wells. Each well has the set limit values of salinity.Based on the operation analysis of wells in different fields, the calculated predicted results of scale deposition in wells according to the existing procedures and their comparison with the factual data from production fields, the specialists of the institute have developed the efficient complex multi-faceted measures.

CO&lt;sub&gt;2&lt;/sub&gt;在原油及高矿化度地层水体系中的溶解试验

CO&lt;sub&gt;2&lt;/sub&gt;在原油及高矿化度地层水体系中的溶解试验

CO&lt;sub&gt;2&lt;/sub&gt;在原油及高矿化度地层水体系中的溶解试验

CO&lt;sub&gt;2&lt;/sub&gt;在原油及高矿化度地层水体系中的溶解试验

Characterization of the boron, lithium, and strontium isotopic variations of oil sands process-affected water in Alberta, Canada

Oil sands operations in Alberta, Canada generate large volumes (>840 × 106 m3) of oil sands process-affected water (OSPW) that contains contaminants that are toxic to aquatic life. OSPW is stored in open tailings ponds and leakage from the ponds presents a potential long-term environmental risk. However, the presence of naturally occurring saline water in the oil sands region in Alberta presents a challenge for delineating the impact of OSPW in cases where OSPW is leaked to the environment. Here, we characterize the inorganic chemistry and isotopic variations of boron (δ11B), lithium (δ7Li), and strontium (εSrSW) of OSPW from tailings ponds in order to evaluate the source of salinity in OSPW and the potential utilization of these isotope ratios as forensic tracers of OSPW migration in the environment. In addition to generating new data, we compiled published data to build a comprehensive dataset of the geochemical composition of different water sources in the oil sands region of Alberta. OSPW is brackish (TDS ∼ 1800 mgL−1), with elevated chloride (392 ± 184 mg L−1), boron (2.2 ± 0.4 mg L−1), and lithium (0.12 ± 0.11 mg L−1) concentrations relative to the Athabasca River that is used for bitumen extraction. OSPW is characterized by narrow ranges of δ11B (23.7 ± 1.8‰), δ7Li (16.3 ± 1.7‰), and 87Sr/86Sr ratios (εSrSW=-3.9 ± 19.2). The geochemical and isotope ratios in OSPW reflect mixing of residual, saline formation water from Lower Cretaceous units with fresh surface water that has been modified by interactions with the solid oil sands. The elevated boron and lithium concentrations and δ11B, δ7Li and εSrSW variations we observed are distinct from the compositions of a shallow freshwater aquifer in the area (8.1 ± 5.0‰, 11.3 ± 0.9‰ and 9.7 ± 5.6, respectively) and the local rivers (15.6 ± 4.7‰, 15.1 ± 1.4‰ and 30.3 ± 16.0). However, groundwater and saline springs in the region presents a wider range of geochemical and isotopic values that are not always distinguishable from OSPW. The integration of boron, lithium, and strontium isotopes provides a potential monitoring tool for tracing OSPW release to local freshwater sources.