Low Oil Saturation Research Articles

COMBINED PROPPANT APPLICATION ON THE WELLS OF THE VOSTOHNO-PRIDOROZHNOE OIL FIELD

Background Hydraulic fracturing is the most common method of intensification. It is used to create new cracks, as well as for the expansion of natural cracks. The main purpose of this method using are to improve communication with the wellbore, to increase the cracks system and to reduce energy costs. For Western Siberia, this method is suitable, since the deposits of this region are characterized by a low permeability, high segregation and low initial oil saturation. Aim and Objective Efficiency determination of the combined proppant application for the hydraulic fracturing at the wells of Vostohno-Pridorozhnoe oil field. Results As a result of the study, it was found that with increasing effective thickness of the formation and proppant mass, the flow rate of the liquid increases after hydraulic fracturing. The effect is achieved when fixing the fracture with multi-component proppants, while drilling out wells is ideal for using more than 6 t of proppant per 1 m of effective thickness of the reservoir. Investigation of the coverage ratio in injection wells in the range of 0.15-0.40 indicates a normal process of oil displacement during hydraulic fracturing of the formation.

Computation of Relative Permeability From In-Situ Imaged Fluid Distributions at the Pore Scale

Summary Image-based computations of relative permeability require a description of fluid distributions in the pore space. Recent advances in imaging technologies have made it possible to directly resolve actual fluid distributions at the pore scale, thus capturing a large field of view for arbitrary wetting conditions, which are numerically difficult to reproduce. In previous studies, fluid distributions were not imaged under in-situ conditions, which may cause the oil (nonwetting) phase to snap off. Consequently, computed oil relative permeability is underestimated, particularly at low oil saturations. This study extends our previous work by imaging fluid distributions under in-situ conditions as a basis for numerical computations. In this study, we perform a steady-state flow test on a homogeneous outcrop sandstone (Bentheimer) core. First, the dry core is imaged in our microcomputed-chromatography (micro-CT) facility. Afterward, the core is fully saturated with 0.4 molar sodium iodide (NaI) solutions. The saturated core is then mounted in a specially designed flow cell that allows the flow experiment to be performed with the core mounted on the CT scanner. Afterward, a steady-state injection of oil and brine is performed at four different oil/water-injection ratios. For each injection ratio, steady-state pressure drop is noted, and in-situ fluid distributions are imaged under flow conditions. These imaged fluid distributions are used to compute image-based relative permeability, whereas the measured pressure drops are used to calculate experimental relative permeability. Results demonstrate that imaging in-situ fluid distributions allows us to overcome significant limitations of our previous work: Namely, measured and computed oil relative permeability are in close agreement across the whole saturation range, and laboratory capillary end effects at the core outlet can be imaged, which allows us to apply a correction to the laboratory-measured data.

Self-Colmatation in terrigenic oil reservoirs of Eastern Siberia

The main objective of this work is to study formation damage phenomenon associated with in-situ migration of fines in rock samples from terrigenic reservoirs of Eastern Siberia experimentally. Results of oil flooding for the wide range of flow rates and permeabilities show that oil does not lead to fine mobilization and its consequent retention with permeability reduction. The permeability decrease is observed only when water is flowing in the porous space. Water itself is shown to be a strong driver of self-colmatation, which is likely because of its intensive physicochemical reaction with pore surface. Performing multiple core flooding tests and analyzing the data, we define the range of rock properties and flow conditions corresponding to development of the situ formation damage (self-colmatation). We classify self-colmatation over 5 types characterized with different behaviors of permeability decrease. We comprehensively study the dependencies of permeability reduction specifics on rock properties and flooding conditions. The dependencies account for multiple parameters correlated with permeability reduction: absolute permeability, residual oil saturation, three characteristic pore diameters, four characteristic grain diameters and four major minerals within the rock structure. We discovered that the increase of formation damages are associated with high absolute permeability and low residual oil saturations. It was shown that characteristic size of migrating fines is 0.01–0.005 mm and the diameter of pores where these fines can be strained is 12 μm. We derive a single numerical criterion to estimate the influence of 13 parameters on colmatation process. The absolute permeability and the fraction of pore throats with diameters higher than 30 μm are shown to be the strongest influencers on colmatation.

Factors influencing oil saturation and exploration fairways in the lower cretaceous Quantou Formation tight sandstones, Southern Songliao Basin, China

Favorable exploration fairway prediction becomes crucial for efficient exploration and development of tight sandstone oil plays due to their relatively poor reservoir quality and strong heterogeneous oil saturation. In order to better understand the factors influencing oil saturation and favorable exploration fairway distribution, petrographic investigation, reservoir properties testing, X-ray diffraction analysis, oil saturation measurement, pressure-controlled mercury injection, and rate-controlled mercury injection were performed on a suite of tight reservoir from the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The sandstone reservoirs are characterized by poor reservoir properties and low oil saturations. Reservoir properties between laboratory pressure conditions and in situ conditions are approximately the same, and oil saturations are not controlled by porosity and permeability obviously. Pores are mainly micro-scale, and throats are mainly nano-scale, forming micro- to nano-scale pore–throat system with effective connected pore–throat mainly less than 40%. Oil emplacement mainly occurs through the throats with average radius larger than 0.25 µm under original geological condition. Moreover, the samples with higher oil saturation show more scattered pore and throat distributions, but centered pore–throat radius ratio distribution. Pore–throat volume ratio about 2.3–3.0 is best for oil emplacement, forming high oil saturation. Quartz overgrowth, carbonate cements, and authigenic clays are the major diagenetic minerals. The reservoirs containing about 4–5% carbonate cements are most preferable for oil accumulation, and oil saturation increases with increasing of chlorite as well. The flow zone indicator is a reasonable parameter to predict favorable exploration targets in tight sandstone reservoirs. The reservoirs with flow zone indicator values larger than 0.05 can be regarded as favorable exploration targets in the K1q4 tight sandstones. According to the planar isoline of average flow zone indicator value, the favorable exploration targets mainly distribute in the delta plain distributary channel and deltaic front subaqueous distributary channel.

Diagenesis and hydrocarbon emplacement in the Upper Triassic Yanchang Formation tight sandstones in the southern Ordos Basin, China

ABSTRACTThe Upper Triassic Yanchang Formation in the southern Ordos Basin is a tight sandstone but productive hydrocarbon exploration target. A variety of analyses, including thin-sections, cathodoluminescence (CL), scanning electron microscope (SEM), X-ray diffraction (XRD), fluorescence, isotope and fluid inclusion, have been used to analyse the reservoir petrology and diagenesis to understand the evolution of reservoir porosity. The sandstones are mostly feldspathic litharenites and lithic arkoses with low porosities (7.6% on average) and extremely low permeabilities (0.49 mD on average). A complex diagenetic alteration history of the reservoir caused different kinds of reduction in reservoir porosity. The carbonate cements are sourced from adjacent organic-rich mudstone and precipitated with a higher content near the edges of sandstone units and a lower content at the centres of sandstone units, resulting in two different diagenetic evolution paths. The analysis of porosity evolution history and hydrocarbon emplacement produced the following conclusions: (1) during the eodiagenesis period, mechanical compaction reduced the primary porosity dramatically from 40 to 19%; and (2) during the mesodiagenesis period, the first-phase oil charged the reservoir (porosity ranging from 14 to 19%) as bitumen along detrital grains forming a preferential pathway for subsequent oil emplacements. In the second-phase of oil charge, the reservoir porosity ranged from 9 to 14% limiting water–rock reactions. During the third-phase of oil charge, porosity of the reservoir remained at 9%. In general, the densification period (with a porosity close to 10%) of the reservoir occurs at the same time as the major oil emplacement and may be an explanation for the low oil saturation of the Chang 8 tight sandstone.

Effect of pore structure on shale oil accumulation in the lower third member of the Shahejie formation, Zhanhua Sag, eastern China: Evidence from gas adsorption and nuclear magnetic resonance

As shale oil occurs primarily in micro–nano pores and fractures, research about the effect of pore structure on shale oil accumulation has great significance for shale oil exploration and development. The effect of pore structure on shale oil accumulation in the lower third member of the Shahejie formation (Es3l), Zhanhua Sag, eastern China was investigated using gas adsorption, soxhlet extraction, nuclear magnetic resonance (NMR) analysis, and field emission scanning electron microscope (FE-SEM) observation. The results indicated that the samples contained a larger amount of ink-bottle-shaped and slit-shaped pores after extraction than before extraction. The pore volume and specific surface area of the samples were approximately 2.5 times larger after extraction than before extraction. Residual hydrocarbon occurred primarily in the free-state form in pores with diameters of 10–1000 nm, which can provide sufficient pore volume for free hydrocarbon accumulation. Therefore, pores with diameters of 10–1000 nm were regarded as “oil-enriched pores”, which are effective pores for shale oil exploration, whereas pores with diameters smaller than 10 nm were regarded as “oil-ineffective pores”. Samples with only well-developed small pores with diameters smaller than 1000 nm showed high oil saturation, whereas samples with both small pores and also relatively large pores and micro-fractures presented low oil saturation. As the minimum pore size allowing fluid expulsion is 1000 nm, pores with diameters greater than 1000 nm were considered as “oil-percolated pores”. Large pores and micro-fractures are generally interconnected and may even form a complex fracture mesh, which greatly improves the permeability of shale reservoirs and is beneficial to fluid discharge.

A Model for Subsurface Oil Pollutant Migration

The subsurface spill of hydrocarbon fluids (from an underground leaking tank or from pipelines) is a widespread problem in the oil industry and hydrology. Under the assumption of low oil saturation, the migration of oil pollutant may be modeled by a nonlinear convection–diffusion equation with power law nonlinearities. The saturation-dependent diffusion coefficient is proportional to a power of saturation for which the exponent may be negative or positive depending on the porous medium and the pollutant characteristics. This paper presents general analytical solutions for the one-dimensional transient saturation distribution in immiscible zone. The solutions describe the longtime behavior of a contaminant oil pollutant caused by a continuous source of contaminant (e.g., leakage from pipelines, disposal dumps or storage tanks). Two general forms corresponding to positive and negative power exponents of the diffusion coefficient are presented. The general forms express implicitly the position as function of oil saturation and time. An alternative explicit closed-form solution near the front position is also proposed. An exact explicit solution is obtained for the particular case of constant diffusion coefficient. The proposed solutions are fully analytical in the sense that they do not require any numerical implementation. The solutions may be used to study the porous medium and pollutant parameters. They can be applied to aquifer contamination problems, and they are also important for the verification of numerical solutions.

Experimental Investigation of the Effect of Polymers on Residual Oil Saturation

Summary Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, and hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation (ROS), to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the waterfloods, with up to 24% lower oil saturation after the polymer flood than after the waterflood. The experimental data are in good agreement with the fractional-flow analysis by use of the assumptions that the true ROSs and endpoint relative permeabilities are the same for both water and polymer. This suggests that, for more-viscous oils, the oil saturation at the end of a waterflood (i.e., at greater than 99% water cut) is better described as “remaining” oil saturation rather than the true “residual” oil saturation. This was true for all the corefloods, regardless of the core permeability and without the need for assuming a permeability-reduction factor in the fractional-flow analysis.

Research on nitrogen foam for enhancing oil recovery in harsh reservoirs

Owing to the simultaneous improvement of swept volume and oil displacement, foam flooding is one of the techniques that has been proven successfully in increasing EOR (Enhanced Oil Recovery). However, foam flooding in a harsh condition has not been fully addressed in the previous studies. The objective of this paper is to investigate the high-temperature and high-salinity resistant foam agents as a displacing chemical for improving the efficiency of oil recovery in harsh conditions. Firstly, the foam agents with excellent performances under harsh reservoir conditions were developed by screening and mixing. Then, the foam properties changing with temperature were studied under high pressure in the oil-free/oil-bearing environments. Finally, based on simulating reservoir formation conditions, a series of researches on the flooding characteristics of nitrogen foam were conducted. Results indicated that the optimum foam agents with low surface tension and high interfacial viscoelastic modulus performed excellently under high-temperature and high-salinity. Foam stability increased remarkably as pressure increased, and also largely affected by temperature. Higher concentration and pressure were in favor of foam properties in the presence of crude oil. In foam flooding experiments, the mobility reduction of foam was observed to be larger in the conditions of high pressure and low oil saturation, and nitrogen foam could significantly control the water cut and improve the oil recovery which were subject to the influencing factors (i.e., initial water cut, injected slug, foam quality, injected volume and foam stability).

Pore-scale Network Modeling of Three-Phase Flow Based on Thermodynamically Consistent Threshold Capillary Pressures. II. Results

We use the model described in Zolfaghari and Piri (Transp Porous Media, 2016) to predict two- and three-phase relative permeabilities and residual saturations for different saturation histories. The results are rigorously validated against their experimentally measured counterparts available in the literature. We show the relevance of thermodynamically consistent threshold capillary pressures and presence of oil cusps for significantly improving the predictive capabilities of the model at low oil saturations. We study systems with wetting and spreading oil layers and cusps. Three independent experimental data sets representing different rock samples and fluid systems are investigated in this work. Different disordered networks are used to represent the pore spaces in which different sets of experiments were performed, i.e., Berea, Bentheimer, and reservoir sandstones. All three-phase equilibrium interfacial tensions used for the simulation of three-phase experimental data are measured and used in the model’s validation. We use a fixed set of parameters, i.e., the input network (to represent the pore space) and contact angles (to represent the wettability state), for all experiments belonging to a data set. Incorporation of the MSP method for capillary pressure calculations and cusp analysis significantly improves the agreement between the model’s predictions of relative permeabilities and residual oil saturations with experimental data.

Comparative assessment of three‐phase oil relative permeability models

AbstractWe assess the ability of 11 models to reproduce three‐phase oil relative permeability ( ) laboratory data obtained in a water‐wet sandstone sample. We do so by considering model performance when (i) solely two‐phase data are employed to render predictions of and (ii) two and three‐phase data are jointly used for model calibration. In the latter case, a Maximum Likelihood (ML) approach is used to estimate model parameters. The tested models are selected among (i) classical models routinely employed in practical applications and implemented in commercial reservoir software and (ii) relatively recent models which are considered to allow overcoming some drawbacks of the classical formulations. Among others, the latter set of models includes the formulation recently proposed by Ranaee et al. (), which has been shown to embed the critical effects of hysteresis, including the reproduction of oil remobilization induced by gas injection in water‐wet media. We employ formal model discrimination criteria to rank models according to their skill to reproduce the observed data and use ML Bayesian model averaging to provide model‐averaged estimates (and associated uncertainty bounds) of by taking advantage of the diverse interpretive abilities of all models analyzed. The occurrence of elliptic regions is also analyzed for selected models in the framework of the classical fractional flow theory of displacement. Our study confirms that model outcomes based on channel flow theory and classical saturation‐weighted interpolation models do not generally yield accurate reproduction of data, especially in the regime associated with low oil saturations, where water alternating gas injection (WAG) techniques are usually employed for enhanced oil recovery. This negative feature is not observed in the model of Ranaee et al. (2015) due to its ability to embed key effects of pore‐scale phase distributions, such as hysteresis effects and cycle dependency, for modeling observed during WAG.

Petroleum source rock potential of the Silurian Dadaş shales in the Hazro and Korudağ regions of Southeast Anatolia, Turkey

Shales of the Silurian Dadaş Formation exposed in the southeast Anatolia were investigated by organic geochemical methods. The TOC contents range from 0.24 to 1.48 wt% for the Hazro samples and 0.19 to 3.58 wt% for the Korudağ samples. Tmax values between 438 and 440 °C in the Hazro samples indicate thermal maturity; Tmax values ranging from 456 to 541 °C in the Korudağ samples indicate late to over-maturity. Based on the calculated vitrinite reflectance and measured vitrinite equivalent reflectance values, the Korudağ samples have a maximum of 1.91%R(g-v), in the gas generation window, while a maximum value of 0.79%R(amor-v) of one sample from the Hazro section is in the oil generation window. Illite crystallinity (IC) values of all samples are consistent with maturity results.Pr/Ph ratios ranging from 1.32 to 2.28 and C29/C30 hopane ratios > 1.0 indicate an anoxic to sub-oxic marine-carbonate depositional environment.The Hazro shales do not have any shale oil or shale gas potential because of their low oil saturation index values and early to moderate thermal maturation. At first glance, the Korudağ shales can be considered a shale gas formation because of their organic richness, thickness and thermal over-maturity. However, the low silica content and brittle index values of these shales are preventing their suitability as shale gas resource systems.

ПЕРСПЕКТИВЫ ПРИМЕНЕНИЯ ТЕХНОЛОГИИ ВЫСОКОЧАСТОТНОГО ВОЗДЕЙСТВИЯ НА ДОБЫЧУ ТЯЖЕЛЫХ УГЛЕВОДОРОДОВ

This article is about of high oil viscosity reservoirs, where due-to low initial oil saturation, presence of gas cap and bottom water, high depth, low thickness the application of «cold» and «thermal» methods is unprofitable, and microwave heating is a perspective technology transport.

An evaluation of enhanced oil recovery strategies for a heavy oil reservoir after cold production with sand

Cold heavy oil production with sand (CHOPS) is the process of choice for unconsolidated heavy oil reservoirs with relatively high gas content. The key challenge of CHOPS is that the recovery factor tends to be between 5% and 15%, implying that the majority of the oil remains in the ground after the process is rendered uneconomic. Continued cold production (without sands) is not productive for a post-CHOPS reservoir because of the low oil saturation and depleted reservoir pressure in the wormhole regions. There is a need to develop viable recovery processes for post-CHOPS reservoirs. Here, different follow-up processes are examined for a post-CHOPS heavy oil reservoir. In post-CHOPS cold water flooding, severe water channeling is ineffective at displacing high viscosity heavy oil. Hot water flooding improves the sweep efficiency and produces more oil compared with cold water flooding. However, the swept region is limited to the domain between the neighboring wormhole networks, and the energy efficiency of the process is relatively poor. Compared with the hot water flooding case, steam flooding achieves higher oil production rates and lower water use. A cyclic steam stimulation strategy achieves the best performance regarding oil production rates and water usage. Based on our results, it is observed that thermally based techniques alone are not capable to recover the oil economically for post-CHOPS reservoirs. However, it is suggested that techniques with combined use of thermal energy and solvent could potentially yield efficient oil recovery methods for these reservoirs. Copyright © 2015 John Wiley & Sons, Ltd.

Subtle oil fields along the Western Flank of the Cooper/Eromanga petroleum system

Oil production from Cooper/Eromanga started in 1978, peaked in the 1980s and began a steady decline. Oil production from the Western Flank commenced in 2002 and has steadily increased. In the year until July 2014, a total of 8.6 million BBL of oil was produced from 16 active fields along the Western Flank, bringing the cumulative total to 24 million BBL. Western Flank oil has underpinned a ten-fold growth in market capitalisation in four listed Australian companies: Beach Energy, Drillsearch Ltd, Senex Energy and Cooper Energy. Two sandstone plays dominate the Western Flank petroleum geology: the Namur Sandstone low-relief structural play and the mid-Birkhead stratigraphic play. The use of 3D seismic has improved the definition of both plays, increased exploration success and optimised field appraisal and development drilling. Success rates have improved despite most Namur structural closures being close to the resolution margin for depth conversions (less than 8 m). Seismic attribute mapping is being refined in the more difficult search for mid-Birkhead stratigraphic traps with recent exploration discoveries indicating improved success. Reservoir properties in the Namur are excellent with multi-Darcy permeability, unlimited aquifer strength, low gas/oil ratio (GOR) and low residual oil saturation. This combination leads to an oil recovery factor greater than 75%. Initial free-flow production rates commonly exceed 6,000 BBL per a day. The mid-Birkhead reservoir is also of high quality but the lack of a strong aquifer drive reduces primary recovery. New and re-processed 3D seismic and water-flood projects are expected to drive further discoveries, reserve and production growth.

Prediction of three-phase oil relative permeability through a sigmoid-based model

Abstract We present a novel methodology for the prediction of three-phase oil relative permeability, k ro , through a sigmoid-based model. This modeling choice allows us to incorporate key effects of the pore-scale phase distributions into the proposed effective empirical model for k ro . Our sigmoid-based model is able to reproduce: (i) oil remobilization induced by gas injection in water-wet media; (ii) a smooth transition towards the layer-drainage regime for low oil saturations; and (iii) the consequent reduction of residual oil saturation in a three-phase system. The ability of our model to embed the effects of these processes into the estimation of oil relative permeabilities is discussed through comparison with previous experimental measurements. Two different procedures, respectively aimed at describing primary gas injection and secondary waterflooding, are proposed for data analysis and interpretation. A remarkably good agreement between model predictions and direct three-phase relative permeability measurements from the literature is observed when model parameters are estimated solely on the basis of two-phase information. The robustness of the proposed methodology is also assessed by comparing estimates of model parameters based on two-phase data against their counterparts estimated within a Maximum Likelihood framework on the basis of three-phase measurements.

Hydrocarbon migration system of Fulaerji oil field, Songliao Basin, NE China

Abstract Through sedimentologic and petroleum geologic analysis of over 300 exploration wells in the north part of the west slope in the Songliao Basin, the conduit role the incised valley played in the oil and gas accumulation of the Fulaerji oil field is investigated. The major pays in the Fulaerji oil and gas field are the second and third members of the Cretaceous Yaojia Formation, where the hydrocarbon comes primarily from the Qijia-Gulong sag about 80 km east. The pathway of long distance hydrocarbon migration is the overlapping sandstone complex which fills the incised valley. The incised valley deposits overlapped on the delta deposits toward basin, and connected with shore-shallow lake sandy beach-bar formed during the highest lake flooding period toward the basin margin, constituting a sand rich sedimentary complex of delta - incised valley filling - shore sandy beach bar. Towards the basin, delta sand branches and pinches out in mudstone (mature source rock), transporting the hydrocarbon generated in the effective hydrocarbon kitchen to the incised valley filling body, the incised valley filling deposits transported hydrocarbon for a long distance to the updip pinching sandy beach bar lithologic trap, giving birth to the Fulaerji oil and gas reservoir. In the sand-rich sedimentary system related to the incised valley filling, the effective hydrocarbon transporting system is limited along Well Du 412 - Du 71 - Du 65 - Jiang 39 - Jiang 41 and Fulaerji oil and gas field. The pure hydrocarbon transporting layer is a water production layer with a high degree of hydrocarbon impregnation and low residual oil saturation. Baiyinnuole, Erzhan, Alaxin, Jiangqiao oil and gas fields distributed like a string of beads in NW are closely related to this effective hydrocarbon transporting system.

Evaluation of Hydrocarbon Saturation Using Carbon Oxygen (CO) Ratio and Sigma Tool


 The main aim of this study is to evaluate the remaining oil in previously produced zones, locate the water productive zone and look for any bypassed oil behind casing in not previously perforated intervals. Initial water saturation was calculated from digitized open hole logs using a cut-off value of 10% for irreducible water saturation. The integrated analysis of the thermal capture cross section, Sigma and Carbon/oxygen ratio was conducted and summarized under well shut-in and flowing conditions. The logging pass zone run through sandstone Zubair formation at north Rumaila oil field. The zones where both the Sigma and the C/O analysis show high remaining oil saturation similar to the open hole oil saturation, could be good oil zones that do not appear to be water flooded. The zones where the Sigma analysis shows high residual oil saturation, which is close to open hole oil saturation and the C/O analysis, show medium residual oil saturation; this could indicate that these zones were fresh water flooded to a certain extent and they still keep some residual oil. If the C/O analysis shows low residual oil saturation, it indicates that these zones were probably fresh water flooded thoroughly. If both Sigma analysis and the C/O analysis show medium residual oil saturation, most probably these zones were saline water flooded to a certain extent and they still keep some residual oil.

Impact of pore-scale three-phase flow for arbitrary wettability on reservoir-scale oil recovery

Abstract Three-phase flow in porous media is of great importance in enhanced oil recovery processes such as Water-Alternating-Gas (WAG) injection. In this work we use a new three-phase flow pore-network model, which fully captures the three-phase microscopic displacement processes, including accurate descriptions of oil films and layers, and which takes realistic 3D pore geometries extracted from pore-space images as an input. The pore-scale model is used to calculate physically robust relative permeability and capillary pressure functions for a range of realistic wettability scenarios. These three-phase flow functions have been used in a heterogeneous reservoir model with a range of equiprobable geological realisations of permeability and porosity distributions to demonstrate their impact on oil recovery after water, gas or WAG injection. Simulations at the pore-scale show that the residual oil saturations for a water-wet system are higher after water flooding compared to the corresponding residual oil saturations after gas injection. Residual oil saturations for oil-wet systems are significantly lower after both water and gas injection. This is due to the presence of stable oil wetting films, which provide hydraulic connectivity at low oil saturations. Simulations at the reservoir scale show that the lowest oil recovery for a water-wet case is obtained when a single fluid (gas or water) is injected; WAG injection yields significantly higher recovery factors. If the reservoir is oil-wet, however, pure gas injection results in the highest oil recovery. Overall, field-scale recovery predictions are very sensitive to the combination of both, different geological models and different three-phase relative permeability functions. Comparing recovery factors for network-derived and empirical relative permeability models demonstrates that the uncertainty in predicting oil recovery resulting from the choice of three-phase relative permeability models can be as large as the geological uncertainty present in a model that has been history matched using production data from a prolonged waterflood. This implies that the choice of three-phase flow functions directly affects the viability of WAG projects.

Distribution and geochemical characteristics of fluids in Ordovician marine carbonate reservoirs of the Tahe Oilfield

The Ordovician carbonate reservoirs in the Tahe Oilfield are highly heterogeneous, which have undergone multiple superimposed transformations by tectonic activities and karst processes, leading to an extremely complex fluid distribution. The geochemical characteristics of geofluids also display great disparities. Results show that the vertical distribution of oil and gas are continuous, how- ever the oil-water interfaces in different blocks of the Tahe Ordovician Oilfield are numerous. Meteoric water infiltration is regarded as the main reason for the high oil-water interface and high water content to the north of Tahe Oilfield, especially in well blocks S78-S73. The isotopic values of deuterium-oxygen in the groundwater and carbon-oxygen from calcite veins confirm that formation water in Ordovician reservoirs of the Tahe Oilfield was a mix of meteoric water and connate water, and the proportion of meteoric water gradually increases from south to north, while connate water decreases. The Tahe Or- dovician reservoirs are characterised by multiple hydrocarbon charges, and the general migrating di- rection is from southeast to northwest and from east to west. High production could be obtained in the northern area of the Tahe Oilfield since the oil layers are thick and oil is highly saturated. The residual water within the reservoirs is low, and heavy oil is dominant in this area. Only a small amount of pore water has been replaced by oil in the southern Tahe Oilfield, leading to low oil saturation and a high content of residual water. Crude oil is herein mainly of medium-light type. During the process of explo- ration in this region, acid fracturing reformation is usually required for wells to increase their output;