АППРОКСИМАЦИЯ ДИАГРАММ КАРОТАЖА ПОТЕНЦИАЛОВ САМОПРОИЗВОЛЬНОЙ ПОЛЯРИЗАЦИИ АНАЛИТИЧЕСКИМИ ФУНКЦИЯМИ ДЛЯ ЭКСПРЕСС-ОПРЕДЕЛЕНИЯ МИНЕРАЛИЗАЦИИ ПЛАСТОВОЙ ВОДЫ

Clays in reservoir rocks have a significant impact on formation evaluation. An important property of clay minerals is their ability to adsorb ions on their exposed surface, which is measured by its cation exchange capacity (CEC). This property can affect saturation calculation if not properly accounted for. Many techniques have been developed for clay characterization, but it remains a focus of frontline research to find an accurate method for quantifying clays in situ and is the main objective of this study. Extensive numerical studies have been conducted and the results have indicated that for a shaly sand formation, strong dielectric dispersions were observed for all the simulated models at frequencies below 1MHz, which allowed an equation to be established that can be used to calculate clay volume through derivatives of the permittivity dispersive curves. In deriving this equation, parameters used for the studies include water-filled porosity, formation water salinity, grain size, clay type and volume, and Archie cementation exponent. The developed model contains two calibration constants, a and b, which need to be predefined. Results indicate that, for the simulated models, b is a constant while a depends on water-filled porosity, formation water salinity, grain size, clay content, and Archie cementation exponent. Data shows that there is no simple way to define constant a, due to its complex relationship with the various parameters. When focusing on relationships between constant a and clay volume and formation water salinity, by assuming other parameters can be estimated either by conventional petrophysical interpretations or laboratory measurements, then the current developed workflows can be used to estimate either clay volume or formation water salinity: Workflow 1: knowing formation water salinity, computing constant a, then estimating clay volume and Workflow 2: knowing clay volume, computing constant a, then estimating formation water salinity. To our knowledge, such an equation is the first model that has never been published before. The correlation works well in the synthetic data. It has a potential to provide a new method for characterizing formation clays and water salinity from low frequency resistivity measurements such as induction logs that is routinely run in almost every well drilled. Thus, it provides a powerful economical tool for enhanced reservoir characterization. Field testing is being conducted.

For big variation of formation water salinity in Chang 8 stratum, Triassic, northwestern Ordos Basin, China, low resistivity contrast exists between oil layers and water layers. In order to increase the accuracy of log interpretation, accurate formation water salinity is a vital part. Based on the petrophysical theory, this paper summarizes and improves two methods to estimate formation water salinity. Firstly, reservoir resistivity-porosity cross plot method is introduced for oil-water layers and water layers. To be specific, resistivity and porosity log values of target reservoir are added to the cross plot. Data points, which are closest to the origin of coordinates, are selected as water layer ones. Then, formation water salinity is calculated by Archie formula. Secondly, shale water salinity is approximately regarded as formation water salinity. Because shale water salinity estimation is a nonlinear problem with small sample sets and there is no theoretical equation, Least Squares Support Vector Machine (LSSVM) is used for shale water salinity prediction. 9 parameters are extracted from lithology, resistivity and porosity log curves, among which, 5 are optimized as sensitive parameters by Principal Component Analysis (PCA). The effectiveness and reliability of resistivity-porosity cross plot and improved SVM method are tested by 23 formation water chemical analysis data. The average relative error of the former method is 19.79%, while that of the latter 27.57%. In addition, formation water salinity of another 50 wells are calculated by the two methods. Based on them, a salinity plane distribution map is drawn by Geomap software. In high salinity area, producing wells gather. Thus, one possible origin of formation water salinity variation is proposed. High salinity water moves into reservoirs with oil from source rock, which leads to high water salinity. In ultra-low permeability clastic reservoir with near source accumulation, formation water salinity probably varies significantly because of oil migration and accumulation. Furthermore, layers with oil often have higher formation water salinity, which is the main cause of low resistivity oil layers. Thus, the accurate formation water salinity calculated by the improved methods, will play an important role in the evaluation of low resistivity contrast oil layers and water layers.

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

Pulsed neutron‐neutron logging is a method that can determine water saturation by means of the formation macroscopic absorption cross section according to thermal neutron time spectra by using He‐3 detector. In this paper, the thermal neutron time spectrums under the conditions of different formation water salinity, porosity, saturation and borehole were simulated by using the Monte Carlo method. The relationship of formation macroscopic cross section and water salinity was studied. It is concluded that the suitable formation water salinity of the PNN logging is about 10 g/L to 100 g/L, and the suitable porosity minimum is about 10% when the formation water salinity measures up to 50 g/L in theory. The formation macroscopic absorption cross section was less affected by borehole fluid although thermal neutron count rate is different. The porosity can be determined by using the thermal neutron count ratio of two different spacing detectors. The evaluation method of matrix and water saturation is put forward according to the formation macroscopic absorption cross section versus porosity under the condition of different lithology and saturation, and then the oil, water and gas reservoir can be identified by the PNN logging. As a whole the PNN logging method is preferable to the low salinity and porosity over the other ways to determine the remaining oil saturation.

Fluid evolution in the Dabei Gas Field of the Kuqa Depression, Tarim Basin, NW China: Implications for fault-related fluid flow

Summary In an era of increasing energy demand, declining oil fields, and fluctuating crude oil prices globally, most oil companies are looking forward to implementing cost-effective and environmentally sustainable enhanced oil recovery (EOR) techniques such as low salinity waterflooding (LSWF) and microbial EOR (MEOR). The present study numerically investigates the combined influence of simultaneous LSWF and microbial flooding for in-situ MEOR in tertiary mode within a sandstone core under spatiotemporally varying pH and temperature conditions. The developed black oil model consists of five major coupled submodels: nonlinear heat transport model; ion transport coupled with multiple ion exchange (MIE) involving uncomplexed cations and anions; pH variation with salinity and temperature; coupled reactive transport of injected substrates, Pseudomonas putida and produced biosurfactants with microbial maximum specific growth rate varying with temperature, salinity, and pH; relative permeability and fractional flow curve variations owing to interfacial tension (IFT) reduction and wettability alteration (WA) by LSWF and biofilm deposition. The governing equations are solved using finite difference technique. Operator splitting and bisection methods are adopted to solve the MIE-transport model. The present model is found to be numerically stable and agree well with previously published experimental and analytical results. In the proposed MIE-transport mechanism, decreasing injection water (IW) salinity from 2.52 to 0.32 M causes enhanced Ca2+ desorption rendering rock surface toward more water-wet. Consequently, oil relative permeability (kro) increases with >55% reduction in water fractional flow (fw) at water saturation of 0.5 from the initial oil-wet condition. Further reducing IW salinity to 0.03 M causes Ca2+ adsorption shifting the surface wettability toward more oil-wet, thus increasing fw by 52%. Formation water (FW) salinity showed minor impact on WA with <5% decrease in fw when FW salinity is reduced from 3.15 to 1.05 M. During low-salinity augmented microbial flooding (LSAMF), biosurfactant production is enhanced by >63% on reducing IW salinity from 2.52 to 0.32 M with negligible increase on further reducing IW and FW salinities. This might be owing to limiting nonisothermal condition (40 to 55°C), dispersion, sorption, and microbial decay. During LSAMF, maximum biosurfactant production occurs at microbial maximum specific growth rate of 0.53 h-1, mean fluid velocity of 2.63×10-3 m h-1 and initial oil saturation of 0.6, thus resulting in significant WA, increase in kro by >20%, and corresponding fw reduction by >84%. Moreover, the EOR efficiency of LSAMF is marginally impacted even on increasing the minimum attainable IFT by two orders of magnitude from 10-3 to 10-1 mN m-1. Though pH increased from 8.0 to 8.9, it showed minor impact on microbial metabolism. Formation damage owing to bioplugging observed near injection point causing increase in fw by ~26% can be mitigated by adopting suitable well-stimulation strategies during the LSAMF run time. The present study is a novel attempt to show synergistic effect of LSAMF over LSWF in enhancing oil mobility and recovery at core scale by simultaneously addressing complex crude oil-brine-rock (COBR) chemistry and critical thermodynamic parameters that govern MEOR efficiency within a typical sandstone formation. The present model with relatively lower computational cost and running time improves the predictive capability to preselect potential field candidates for successful LSAMF implementation.

Summary This paper presents the principles of dielectric logging by describing measurement of phase shift. laboratory experiments, theoretical calculations for determining the vertical resolution and depth of investigation, and results of application in field practice. Introduction Measurement of oil saturation is an important pan of well logging in the development of- an oil field. It is an important basis for evaluating watered-out reservoirs, estimating the residual oil, and redividing and combining the productive zones. In the development of an oil field by water injection, the salinity of injected water always differs greatly from that of original formation water. For example, the salinity of original formation water in Daqing oil field is about 6,000 to 8,000 ppm, and the salinity of the injected water is as low as 500 to 800 ppm. Thus, the formation water gradually becomes less saline as the amount of injected water is increased. However, the resistivity log and the Neutron Lifetime Log- cannot be used to measure oil saturation in such strata. To solve this problem, it is necessary to introduce other logging methods for measuring oil saturation that are less influenced by the salinity of formation water. Dielectric constant logging is one method to solve this problem and has been described in U. S. and Soviet literature. In the late 1960's, the study of dielectrologs was launched in Daqing oil field. Both theoretical and experimental studies on dielectrologs were carried out. Since 1974, the dielectrolog tool has been used in the field and has been run in more than 100 downhole operations. Field practice has proved that the accuracy for interpreting water saturation of formation and watered-out zones with dielectrolog is +/-8. 8% and +/-5. 7%, respectively. Laboratory Experiment For Determining Dielectric Constant of Rocks The dielectric constants for crude oil and minerals of sedimentary rocks are small (2 to 8), and that for water is very high (80). Therefore, the dielectric constant for water-bearing rocks depends mainly on its water volume. To verify the fundamental principle of this logging method, a laboratory study of main factors affecting the dielectric constant of rocks was performed with core samples from different oil-beefing zones in Daqing oil field. The frequency used here is 60 MHz. Fig. 1 gives the relationship between the dielectric constant and formation water volume of sandstone samples from different regions of Daqing oil field. Air saturation is used instead of oil saturation in these experiments. In Fig. 1 the dielectric constants of rocks correspond very well with the water volume. The dielectric constants of dry samples range from 4 to 7; those of rock matrix, oil, and air are rather small because they depend on shift polarization. JPT P. 1797^

Summary Test data show that formation water salinity varies greatly in the study reservoirs with complex wettability. The common methods to predict formation water salinity have failed, which brings great difficulty to predict reservoir oil saturation. Therefore, assuming formation water salinity of sandstones is approximately equal to bound water salinity of adjacent mudstones, stable parts of adjacent mudstones are firstly selected to acquire resistivity and interval transit time. Secondly, compaction correction of interval transit time is completed. Then, a novel method of determining formation water salinity based on adjacent mudstone information is proposed by cross plot of resistivity and corrected interval transit time, which can be used to predict formation water salinity under different conditions (0 - 20 g/L, 20 - 40 g/L, 40 - 60 g/L and larger than 60 g/L). Finally, formation water salinity of 106 wells is predicted, and plane distribution contour map of the study area is drawn in combination with other 69 formation water salinity analysis data, which is helpful to study the accurate selection and plane distribution laws of formation water salinity. It provides a feasible solution for formation water salinity prediction in ultra-low permeability reservoirs with complex wettability, which can be applied universally.

<p>The paper presents the results of a novel integrated solution of formation water content and salinity determination of the low permeability reservoir rock of Bazhenov formation (West Siberia, Russia) for petrophysical characterization. The workflow is based on three techniques: evaporation method (EM) with isotopic composition analysis, analysis of water extracts, and cation exchange capacity (CEC) study. The EM offers a fast, efficient, and accurate measurement of the residual water content with breakdown to free and loosely clay-bound types. The isotopic composition reveals the origin and genesis of pore water. The chemical analysis of water extracts delivers a lower bound salinity in terms of NaCl. CEC describes rock-fluid interactions. The two methods of cation exchange capacity (CEC) measurement were applied – alcoholic NH<sub>4</sub>Cl ((NH<sub>4</sub>Cl)Alc) and hexammnninecobalt(III) chloride (CoHex) method. Both showed similar results. CEC varies from 2.87 to 5.82 meq/kg by ((NH<sub>4</sub>Cl)Alc method and from 2.87 to 6.38 cmol/kg by CoHex method and depends on the clay content. Ca, Na, Mg, K form exchange complex of all studied core samples. According to interrelation (rNa+rK)>rCa the exchange complex type is marine and was inherited from the composition of the paleobasin seawater.</p><p>The target rock samples contained the residual formation water 0.11–4.27 wt.%, including free 0.04–3.92 wt.% and loosely clay-bound water 0.09–0.96 wt.%. The loosely bound water content correlates well to the clay mineral fraction. The amount of chemically bound water fell in a range of 0–6.40 wt.% and exceeds that of free and loosely bound water.</p><p>We found that water extract composition depends on the core mineral content, except chlorine and bromine, which originates from the pore water. Using the thermodynamic modelling in PHREEQC program, next ratio of cations in pore water was found - Na (up to 91%), Mg (up to 5.6%), Ca (up to 2.6 %) and K (up to 0.8%). According to the calculation using the water extracts results, the pore water salinity as NaCl changes from 1.23 to 21.96 g/L. The corresponding isotopic composition indicated the deep formation genesis and generally correlated to that of the deep stratal waters of the West Siberia. Isotopic composition proved the formation origin of extracted pore water samples.</p><p>The study made a qualitative step up towards the quantitative characterization of formation water in shale reservoir rocks with the initial water content of less than 1 wt.%.</p><p><span>This work was supported by the Russian Science Foundation (grant No. 17-77-20120).</span></p>

The accurate determination of formation water salinity is crucial for petroleum exploration and development as it plays a significant role in determining reservoir parameters. In particular, salinity determines the sigma value of formation water in pulsed-neutron capture logging, which is essential for calculating reservoir oil saturation. Therefore, accurate measurement of formation water salinity provides vital information for determining reservoir parameters, understanding the origin of formation water salinity, assessing oil and gas preservation conditions, and predicting oil reserves. Currently, the determination of borehole fluid and formation water salinity typically involves sampling analysis, which can be expensive and may not accurately represent the salinity distribution of the reservoir. Additionally, the presence of shale presents challenges to the effectiveness of formation resistivity logging in calculating formation water salinity. In cases where the salinity is high, the formation resistivity logging may fail to accurately calculate the salinity, which is a difficulty in determining the salinity of the formation water. In the field of nuclear logging, attempts have been made to monitor formation water salinity by combining thermal neutron count and chlorine yield. However, this method has limitations and cannot be applied to reservoirs with complex lithology. Therefore, addressing the calculation error of chlorine yield and content is a crucial issue to overcome in the quantitative monitoring of formation water salinity. This paper presents a novel joint bispectral method for accurately calculating formation water salinity using elemental spectroscopy logging technology. The method utilizes inelastic and capture energy spectra to determine the element yield, which is then converted into the atomic number proportion (ANP) of each element. Based on the ANP values and the relative atomic mass of the element, the formation chlorine content is directly calculated. Subsequently, a high-precision calculation model of formation water salinity is constructed by utilizing formation density and porosity information. Compared to the traditional oxygen closure model, the joint bispectral method improves the calculation accuracy of chlorine content by an order of magnitude and keeps the calculation error of formation water salinity within 2 g/L. The field logging example further demonstrates the high agreement between the calculated results of formation water salinity and laboratory analysis results, validating the validity and accuracy of the joint bispectral method. This method is not affected by the mineral composition of the formation, making it highly versatile and suitable for a wide range of applications. It provides valuable technical support for the exploration and development of oil and gas in saltwater-bearing reservoirs.

ABSTRACTDuring microbial enhanced oil recovery (MEOR) processes, the interaction between injection water (IW) and formation water (FW) salinity causes in-situ salinity variation which affects the final oil recovery. The present study explicitly quantifies the Original Oil in Place (OOIP) recovered for different IW and FW salinity conditions through numerical simulation. Based on simulation results, user-friendly empirical correlations were deduced to quickly estimate the OOIP. The results suggest that the OOIP increases drastically in all reservoirs with any initial FW salinity as the adopted salinity of IW is lowered. The study would serve as a tool for making reservoir management decisions.

Boron (Gadolinium) Neutron Lifetime Logging is a new logging method to detect and determine residual oil distribution of sandstone reservoirs at the stages of high and super-high water cut. For most oilfields in China, because formation water salinities are generally lower than 20000ppm, the conventional neutron lifetime logging prevailing in high salinity of formation water will not be effective. However, the use of boron or gadolinium as indicator to carry out neutron lifetime logging has been proved to be very effective in these oilfields. By using this method, a correct water plugging operation was then done for six production wells, which were at high water cut stage in a certain development zone of Daqing Oilfield. The results showed that, for each well, the average oil production rate could be increased by 6.2 t per day, and the average water production rate could be decreased by 70.6 cubic meters per day, the ratio of net income to total investment was expected to be 5:1. Both the repeated logging data and the comparison with other logging data, such as fluid entry profile, temperature and noise data etc., demonstrated that this method presented in the paper is reliable and feasible, regardless of the variations of lithology, formation water salinity and casing size. Introduction Residual oil saturation is an important parameter for oilfield development. At the later development stage of high water cut (the combined water cut is more than 80%), oil and water distribution is very complex, water flooded and unflooded areas are jigsaw-like, the strength of water drive is great disparity in such multi-zonal oilfields as Daqing. The establishments of the measures of tapping potentials, the schemes of well pattern infilling and tertiary oil recovery all require to accurately, at least basically accurately realize the amount and distribution of residual oil. The distribution research of residual oil becomes the focus and difficulty in oilfield development. At present, the methods for determining residual oil saturation are much more, such as sealing core drilling, single well tracer, well logging, material balance method and so on. By comparison, geophisical well logging has maximum potentialities, since it can continuously measure the whole interval at any time according to the actual requirement, and it is benefit as well as convenient. Neutron lifetime logging is one of pulsed neutron logging, it is also one of the main methods for determining residual oil saturation and generally used in high water salinity and high porosity formation(the total salinity of formation water is more than 150000ppm, the porosity is over 15%). Since neutron lifetime logging data are effected by various factors, the number of unknown variables are increased in interpretation equations and the accuracy of traditional neutron lifetime quantity interpretation is effected. Therefore, logging-injection-logging technology was put forward and applied to eliminate the difficulties in various parameters determination and effects resulted from the uncertainty of multiple unknown variables. Since most oilfields in China belong to low water salinity oilfields, the total salinity of formation water is generally below 20000ppm, the application of neutron lifetime logging is restricted. Some oilfields have attempted to increase the salinity of injected water with NaCl and make logging-injection-logging experiments in low water salinity formation, otherwise, since it was difficult to make up and the work load was heavy, the deviation of measured capture cross-section was not big enough, the reliability of data and economic benefit were not good, it was unable to popularize. Neutron lifetime logging with boron or Gadolinium compound solution, the interpretation method and the results of field application are presented in this paper. Proved by practice, the data interpretation results are accurate and reliable and widely applicable. The method has a widely popularizing prospect.

Summary In this study, we aim to develop a new integrated solution for determining the formation water content and salinity for petrophysical characterization. The workflow includes three core components: the evaporation method (EM) with isotopic analysis, analysis of aqueous extracts, and cation exchange capacity (CEC) study. The EM serves to quickly and accurately measure the contents of both free and loosely clay-bound water. The isotopic composition confirms the origin and genesis of the formation water. Chemical analysis of aqueous extracts gives the lower limit of sodium chloride (NaCl) salinity. The CEC describes rock-fluid interactions. The workflow is applicable for tight reservoir rock samples, including shales and source rocks. A representative collection of rock samples is formed based on the petrophysical interpretation of well logs from a complex source rock of the Bazhenov Formation (BF; Western Siberia, Russia). The EM employs the retort principle but delivers much more accurate and reliable results. The suite of auxiliary laboratory methods includes derivatography, Rock-Eval pyrolysis, and X-ray diffraction (XRD) analysis. Water extracts from the rock samples at natural humidity deliver a lower bound for mineralization (salinity) of formation water. Isotopic analysis of the evaporated water samples covered δ18O and δ2H. A modified alcoholic ammonium chloride [(NH4Cl)Alc] method provides the CEC and exchangeable cation concentration of the rock samples with low carbonate content. The studied rock samples had residual formation water up to 4.3 wt%, including free up to 3.9 wt% and loosely clay-bound water up to 0.96 wt%. The latter correlates well to the clay content. The estimated formation water salinity reached tens of grams per liter. At the same time, the isotopic composition confirmed the formation genesis at high depth and generally matched with that of the region's deep stratal waters. The content of chemically bound water reached 6.40 wt% and exceeded both free and loosely bound water contents. The analysis of isotopic composition proved the formation water origin. The CEC fell in the range of 1.5 to 4.73 cmol/kg and depended on the clay content. In this study, we take a qualitative step toward quantifying formation water in shale reservoirs. The research effort delivered an integrated workflow for reliable determination of formation water content, salinity lower bound, and water origin. The results fill the knowledge gaps in the petrophysical interpretation of well logs and general reservoir characterization and reserve estimation. The research novelty uses a unique suite of laboratory methods adapted for tight shale rocks holding less than 1 wt% of water.

Saturations initially computed from Pulsed Neutron Capture log response usually vary significantly from final or "refined" values. In many instances, considerable juggling of "fixed" parameters is necessary before reasonable saturations are derived. Slight variations in water salinity, shaliness, hydrocarbon or rock matrix capture cross sections can result in significant saturation uncertainties. This study primarily concerns a statistical study of log response opposite zones of known saturation conditions and formation water salinity. A technique to compensate for shaliness based on relative natural gamma ray deflection is developed. The average relationships presented represent a standard error for computed water saturations of ±15 saturation percent. Normalizing techniques utilizing one or more intervals in which saturation conditions are known can substantially reduce this error. Introduction Since the introduction of Pulsed Neutron Capture logging, over 130 Neutron Lifetime Logs (Dresser Atlas)1 and 30 Thermal Decay Time logs (Schlumberger)2 have been run in Shell's South Pass Block 24 and South Pass Block 27 Fields. In many cases, quantitative interpretation of the log is difficult primarily because of wide variations in computed matrix capture cross sections (Sma) lack of porosity control, uncertainty in hydrocarbon capture cross sections, and the inability to compensate for shaliness. All of the major producing horizons in the two fields are broken sand-shale sequences, normally compacted, with sand quality primarily varying with the degree of silt and clay content. Since "trend" analyses and normalizing techniques have proven effective in handling uncertain petrophysical parameters for similar sedimentary sections, the techniques were applied to PNC log interpretation. Before any shaliness correction based on relative gamma ray deflection can be developed, one of the following assumptions must be made: Shale is interbedded or laminated with clean sand. Shale or clay is evently distributed within the sand matrix. A combination of the above.

CO2 miscible flooding is an important technology for enhancing oil recovery and greenhouse gas storage in the world. As a tertiary recovery technology, it is usually applied after water flooding. Therefore, the actual reservoirs usually contain a lot of injected water in addition to connate water. The salinity of these formation waters varies from place to place. CO2 is an acid gas. After it is injected into the reservoir, it easily reacts with formation water and rock and affects the physical properties of the reservoir. However, no research results have been reported whether this reaction affects the minimum miscibility pressure (MMP) of CO2-crude oil, a key parameter determining miscible flooding in formation water. Based on CO2-formation water–rock interaction experiments, this paper uses the core flooding method to measure the CO2-crude oil MMP under different salinity in formation water. Results show that CO2 causes a formation water pH decrease from 7.4 to 6.5 due to its dissolution in formation water. At the same time, CO2 reacts with formation water, albite, potassium feldspar, and carbonate minerals in the cores to generate silicate and carbonate precipitates, which could migrate to the pore throat together with the released clay particles. Overall, CO2 increased core porosity by 5.63% and reduced core permeability by 7.43%. In addition, when the salinity of formation water in cores was 0, 4,767, and 6,778 mg/L, the MMP of CO2-crude oil was 20.58, 19.85, and 19.32 MPa, respectively. In other words, the MMP of CO2-crude oil decreased with the increase of salinity of formation water.