Laboratory Coreflood Research Articles

Characterisation of formation damage during reactive flows in porous media

Precipitation of solids due to chemical reactions or thermodynamic non-equilibrium is a common cause of formation damage in oil and gas wells. The traditional mathematical model for reactive flow in porous media contains two empirical parameters: the kinetics rate coefficient, which along with the reagent's concentrations determines the reaction rate; and the formation damage coefficient, which reflects the permeability reduction due to solid phase precipitation. These parameters are determined from laboratory coreflooding tests, which involve commingled injection of reacting fluids. A routine laboratory method determines the kinetics rate coefficient from expensive and cumbersome reagent concentration measurements at the core outlet, after which the formation damage coefficient can be calculated using inexpensive and robust pressure drop measurements. The current paper developed a laboratory method for determining both coefficients from pressure measurements only. The method utilised pressure measurements at the core inlet, outlet and some intermediate core port during commingled quasi-steady-state flow of incompatible fluids. The above data treatment was based on the analytical model for one-dimensional commingled flow of reacting fluids. The formulae for determining the model coefficients from pressure measurements have been derived. The intervals for inverse solution existence, uniqueness, and stability were established. The proposed method was validated by high agreement between the model constants determined by the customary method and the three-point-pressure method.

Fast imaging of laboratory core floods using 3D compressed sensing RARE MRI

Three-dimensional (3D) imaging of the fluid distributions within the rock is essential to enable the unambiguous interpretation of core flooding data. Magnetic resonance imaging (MRI) has been widely used to image fluid saturation in rock cores; however, conventional acquisition strategies are typically too slow to capture the dynamic nature of the displacement processes that are of interest. Using Compressed Sensing (CS), it is possible to reconstruct a near-perfect image from significantly fewer measurements than was previously thought necessary, and this can result in a significant reduction in the image acquisition times. In the present study, a method using the Rapid Acquisition with Relaxation Enhancement (RARE) pulse sequence with CS to provide 3D images of the fluid saturation in rock core samples during laboratory core floods is demonstrated. An objective method using image quality metrics for the determination of the most suitable regularisation functional to be used in the CS reconstructions is reported. It is shown that for the present application, Total Variation outperforms the Haar and Daubechies3 wavelet families in terms of the agreement of their respective CS reconstructions with a fully-sampled reference image. Using the CS-RARE approach, 3D images of the fluid saturation in the rock core have been acquired in 16min. The CS-RARE technique has been applied to image the residual water saturation in the rock during a water-water displacement core flood. With a flow rate corresponding to an interstitial velocity of vi=1.89±0.03ftday−1, 0.1 pore volumes were injected over the course of each image acquisition, a four-fold reduction when compared to a fully-sampled RARE acquisition. Finally, the 3D CS-RARE technique has been used to image the drainage of dodecane into the water-saturated rock in which the dynamics of the coalescence of discrete clusters of the non-wetting phase are clearly observed. The enhancement in the temporal resolution that has been achieved using the CS-RARE approach enables dynamic transport processes pertinent to laboratory core floods to be investigated in 3D on a time-scale and with a spatial resolution that, until now, has not been possible.

Slow migration of detached fine particles over rock surface in porous media

Fines migration involving particle detachment in natural reservoirs usually exhibits significant permeability damage. This occurs due to mobilization and migration of detached colloidal or suspended fines that were strained in thin pore throats. Numerous laboratory coreflood tests show that the time for permeability stabilization accounts for hundreds of injected pore volumes. However, classical filtration theory assumes that the released fines are transported by the bulk of the carrier fluid, thus stabilizing the permeability after the injection of one pore volume. The current paper attributes the stabilization delay to the slow drift of the mobilized fines near the pore walls. We propose basic flow equations for single-phase particle transport in porous media with velocity lower than the carrier fluid velocity. We derive an analytical model for one dimensional flow with particle release and straining under piecewise-constant increasing velocity. The laboratory data are in high agreement with the results of mathematical modelling. The effective particle speed is 500–1000 times lower than the water velocity.

Experimental Investigation of Stress-Dependency of Relative Permeability in Rock Fractures

This study investigates the stress-dependency of relative permeability in rock fractures. Previous studies provide contradictory evidence of the influence of increasing stress on the relative permeability of fractures. Some studies suggest that irreducible water saturation increases, while others show the reverse. In an attempt to resolve these differences, laboratory core flooding experiments are applied to measure the relative permeability of nitrogen–water mixtures in a fracture under various states of effective stress. Simultaneous X-ray CT measurements are made of aperture and water saturation distributions in the fracture. Two effective stress levels, 2.07 and 5.52 MPa, are applied to investigate the stress-dependency. For both states of stress, the measurements show that the relative permeability to gas is very low until a critical saturation is reached. As gas saturation increases beyond the critical value, relative permeability to gas increases quickly while water becomes essentially immobile. Results also demonstrate that increasing stress lowers the irreducible water saturation and the end-point non-wetting phase relative permeability when the experiments are conducted at the same flow rate. Using invasion percolation theory with the fracture aperture maps made at the two different effective stresses, capillary pressure curves are calculated and used to explain changes in phase interference at different stress levels. Finally, the preferential flow paths are analyzed at both stress levels. We use this analysis to reconcile flow regimes observed in earlier studies, and conclude that the differences between them can be explained by the relative importance of viscous and capillary forces. Specifically, if the experiments are designed to keep the capillary number constant, the irreducible water saturation increases with increasing confining stress. If the experiments are conducted at the same flow rate, higher confining stress decreases the irreducible water saturation, as was observed in these experiments. The analysis and data presented here also suggest that small increases in the water saturation of a fracture may dramatically reduce gas flow rates. This may present an additional and unexplored explanation for rapid production decline of gas wells in fractured reservoirs.

Characterization of Biosurfactant Produced by Bacillus licheniformis TT42 Having Potential for Enhanced Oil Recovery.

Bacillus licheniformis TT42 produced a low-molecular weight anionic biosurfactant that reduced the surface tension of water from 72 to 27mN/m and the interfacial tension from 12 to 0.05mN/m against crude oil. We have earlier reported significant enhancement in oil recovery in laboratory sand pack columns and core flood studies, by biosurfactant-TT42 compared to standard strain, Bacillus mojavensis JF2. In the context of this application of the biosurfactant-TT42, its characterization was deemed important. In the preliminary studies, the biosurfactant-TT42 was found to be functionally stable at under conditions of temperature, pH, and salinity generally prevalent in oil reservoirs. Furthermore, the purified biosurfactant-TT42 was found to have a CMC of 22mg/l. A newly developed activity staining TLC method was used for the purification of biosurfactant-TT42. Structural characterization of biosurfactant-TT42 using TLC, Fourier transform infrared spectroscopy (FTIR), GC-MS, and matrix-assisted laser desorption ionization time of flight (MALDI-TOF)/TOF suggested that it was a mixture of lipopeptide species, all having a common hydrophilic cyclic heptapeptide head with the sequence, Gln-Leu/Ileu-Leu/Ileu-Val-Asp-Leu/Ileu-Leu/Ileu linked to hydrophobic tails of different lengths of 3β-OH-fatty acids bearing 1043, 1057 and 1071 Da molecular weight, where 3β-OH-C19 fatty acid was predominant. This is the longest chain length of fatty acids reported in a lipopeptide.

EOR Potential of Mixed Alkylbenzenesulfonate Surfactant at Low Salinity and the Effect of Calcium on “Optimal Ionic Strength”

The enhanced oil recovery (EOR) potential of different alkylbenzenesulfonate surfactants was investigated in a combined study of crude oil–water phase behavior and interfacial tension (IFT) and macroscopic oil displacement studies. In the presence of small amounts of calcium ions (calcium/sodium = 4 mol %), ultralow oil–brine IFT (<0.001 mN/m) was observed at ionic strengths 10 times lower than “optimal salinity” with sodium chloride only; this suggested an application in low salinity surfactant (LSS) EOR. “Optimal ionic strength” was determined for different calcium/sodium ratios in the brine, which further allowed prediction of phase behavior and IFT range for a given surfactant and a given crude oil at different brine compositions. In laboratory core floods, crude oil displacement by LSS with an optimal ionic strength electrolyte was around 9% higher than at “non-optimal” conditions.

Rate-dependent polymer adsorption in porous media

Laboratory core flood experiments were conducted at different flow rates with partially hydrolysed polyacrylamide (HPAM) oilfield Enhanced Oil Recovery (EOR) polymer and silica sand to investigate the polymer retention in porous media due to flow rate variation. Specifically, the double-polymer bank method was used in a new way to quantify and understand total incremental retention (both reversible and irreversible) induced by flow rate variation for HPAM polymers. Experimental results indicate that adsorption was the dominant retention mechanism. Further, the results obtained show that polymer adsorption was rate-dependent (i.e., as flow rate increased, adsorption increased), and that the adsorption was largely reversible with minimal incremental irreversible adsorption. It was also observed that flow rate impacted polymer inaccessible pore volume (IAPV) decreasing from 32% to 15% as flow rate increased from 0.8 ml/min to 6.0 ml/min. Finally, results from the study also give better insight into understanding HPAM flow-induced adsorption and their effect on permeability reduction processes.

Heavy oil polymer flooding from laboratory core floods to pilot tests and field applications: Half-century studies

Reservoir development is increasingly moving towards the heavy oil resources due to the rapid decline in conventional oil reserves. With the production of conventional low gravity crude oil being surpassed by heavy oil production in Alberta, the vast fields of heavy oil have been considered an emerging source of energy to the growing demands for oil and gas. Although the applications of thermal methods have been successful in many enhanced oil recovery (EOR) projects, they are usually uneconomic or impractical in deep and thin pay zones reservoirs. Therefore, polymer flooding is a preferred EOR technique in such reservoirs. An application of polymer flooding in heavy oil reservoirs dates back to more than half a century ago. However, it has long been considered a suitable method for reservoirs with viscosities up to 100 cP only. Recently, this EOR technique has attracted great attentions and become a promising method for oil recovery from heavy oil reservoirs with viscosities ranging from several hundreds to several thousands of centipoises. The main reasons for such a widespread application of the technique in heavy oil reservoirs during the last two decades have been rises in oil prices, extensive use of horizontal wells and advances in the polymer manufacturing technology. This paper aims to review the advances and technological trends of polymer flooding in heavy oil reservoirs since the 1960s. Upon the review, complete data sets of the laboratory works, pilot tests and field applications are established. The database provides qualitative description and quantitative statistics regarding both scientific research and practical applications. Then suitable ranges of some crucial affecting reservoir properties and polymer characteristics for successful field applications are examined. Finally, new screening criteria are developed specifically for heavy oil reservoirs based on an analysis of the data. The criteria are compared with the previously established ones. The outcome of this paper can be used as guidelines for screening, planning, design and eventually implementation of future projects.

Formation damage due to fines migration and its remedial methods

Well productivity decline have been widely observed for gas wells producing the reservoir fines. The phenomenon has been explained by the lifting, migration and subsequent plugging of the pores by the fine particles, finally resulting in permeability decrease. It has been observed in numerous core flood tests and field cases.This paper is based on a study and evaluation of a gas field in the North-western margin of the Nile Delta. It is a super gas field with current production capability of 0.8Bcf/d. It has the potential to produce above this level with the current stock of wells but have only been limited to this through-put due to considerable losses in well productivity that the wells have experienced in recent years due to fines migration phenomenon.Well testing analysis and well performance analysis were done to detect formation damage and provide an overall measure of formation damage. Laboratory core flood tests had been used to determine the causes, degree, and extent of damage. Scanning electron microscopy (SEM) was used to analyze the rock samples used for the core flood test before and after the test. Core flood test had been done to evaluate the effect of acid on improving and curing damaged cores. Matrix acid stimulation on a case study from the studied field was evaluated.

The Use of Polymer-gel Solutions for CO2 Flow Diversion and Mobility Control within Storage Sites

This paper presents a study on the use of polymer-gel technology as an option to remediate non-conformal flow behaviour of CO2 within the storage reservoir. Several polymer-gels with crosslinkers were tested. The rheology, gelation and working times of these polymer-gels at various concentrations were characterised under different temperatures representative of CO2 storage reservoirs. Laboratory core flooding experiments were then carried out on high permeability core samples to test the suitability of polymer-gel solution for flow through and containment of CO2 in porous media. The core samples saturated with brine were subjected to polymer-gel injection. Core sample permeability for CO2 was then measured and the change in CO2 permeability of the sample before and after polymer-gel injection was noted. Reservoir simulations for different scenarios of flow diversion were carried out using the permeability reduction results from the laboratory work on a realistic reservoir model with faults and high permeability channel structures.

Performance evaluation and mechanisms study of near-miscible CO2 flooding in a tight oil reservoir of Jilin Oilfield China

Jilin Oilfield has been conducting a large-scale demonstration project on CO2 EOR and storage in China. CO2 separated from a nearby natural gas reservoir (15–30 vol% CO2) has been injected into the northern part of H-59 oil block with the permeability of 3.0 mD and porosity of 12.7%. After six years of operation, nearly 0.26 million ton of CO2 (0.32 Hydrocarbon Pore Volume) has been injected under a miscible or near-miscible flooding mode with CO2 utilization efficiency of 6.3 MScf/bbl, and an expected enhanced oil recovery of over 10% would be achieved. A systematic and thorough reservoir surveillance program has been conducted to facilitate efficient operation and evaluation. Casing annulus gas composition was analyzed to monitor gas breakthrough in production wells as well as the gas tracer to detect CO2 flow across the reservoir. Bottom hole pressure (BHP) survey of producers and fluid sampling were combined to evaluate the miscibility effect in conjunction with the injection-production data analysis. It is revealed that the designed miscible flooding is best described as near-miscible due to the large pressure difference between injector and producer, and the gas channeling and fractures/heterogeneities cause the miscibility instability. Gravity-stabilized displacement may develop in the downdip part of the reservoir during the flooding process. The vaporization and condensation effects have been observed and confirmed through laboratory core flooding and field produced oil compositions analysis. A key insight from the evaluation study is that CO2 near-miscible flooding is more flexible and easily realizable relative to miscible, particularly in the tight oil reservoir. Further study would be necessary to optimize the reservoir development program under the near-miscible flooding design.

Deep bed and cake filtration of two-size particle suspension in porous media

Abstract Formation of low permeable external filter cake during drilling and water injection has been widely reported in the literature. It may cause significant decrease in well index. The process is very sensitive to size distribution of injected particles. We propose a new mathematical model for cake formation with deep bed filtration for two-particle-size injection. The basic equations account for three stages: formation of cake from large particles with simultaneous deep bed filtration of small particles; small particle capture in the cake with formation of the internal cake inside the external cake; build-up of the uniform cake from the mixture of two-size particles. The analytical model is derived for three stages. Two regimes of the cake formation are identified, which correspond to the high and low concentrations of injected small particles. The laboratory coreflood with two-particle-size suspension injection with monitoring the rate and pressure drop along the core is performed. The matched mathematical model shows good agreement with the laboratory data.

Evaluation of the performance of polymer gels mixed with asphalt particle as a novel composite profile control system

This paper presents gels with asphalt particle (GAP) as a novel composite profile control system, which has better sealing effect for plugging channeling in fractured reservoir. This composite agent was prepared by modified asphalt particle and polymer gels served as suspension. Laboratory core–flood tests showed good injectiviy of GAP solution in high permeability zone with a high plugging rate. Also, the enhance oil recovery mechanism of GAP and polymer gels in fractured reservoir were compared by parallel core–flood test. Simulation results indicate longer response time and better enhance oil recovery for GAP than polymer gels in fractured system.

History Matching Heterogeneous Coreflood of CO2/Brine by Use of Compositional Reservoir Simulator and Geostatistical Approach

Summary Numerical modeling and simulation are essential tools for developing a better understanding of the geologic characteristics of aquifers and providing technical support for future carbon dioxide (CO2) storage projects. Modeling CO2 sequestration in underground aquifers requires the implementation of models of multiphase flow and CO2 and brine phase behavior. Capillary pressure and relative permeability need to be consistent with permeability/porosity variations of the rock. It is, therefore, crucial to gain confidence in the numerical models by validating the models and results by use of laboratory and field pilot results. A published CO2/brine laboratory coreflood was selected for our simulation study. The experimental results include subcore porosity and CO2-saturation distributions by means of a computed tomography (CT) scanner along with a CO2-saturation histogram. Data used in this paper are all based on those provided by Krause et al. (2011), with the exception of the CT porosity data. We generated a heterogeneous distribution for the porosity but honoring the mean value provided by Krause et al. (2011). We also generated the permeability distribution with the mean value for the whole core given by Krause et al. (2011). All the other data, such as the core dimensions, injection rate, outlet pressure, temperature, relative permeability, and capillary pressure, are the same as those in Krause et al. (2011). High-resolution coreflood simulations of brine displacement with supercritical CO2 are presented with the compositional reservoir simulator IPARS (Wheeler and Wheeler 1990). A 3D synthetic core model was constructed with permeability and porosity distributions generated by use of the geostatistical software FFTSIM [Jennings et al. (2000)], with cell sizes of 1.27×1.27×6.35 mm. The core was initially saturated with brine. Fluid properties were calibrated with the equation-of-state (EOS) compositional model to match the measured data provided by Krause et al. (2011). We used their measured capillary pressure and relative permeability curves. However, we scaled capillary pressure on the basis of the Leverett J-function (Leverett 1941) for permeability, porosity, and interfacial tension (IFT) in every simulation grid cell. Saturation images provide insight into the role of heterogeneity of CO2 distribution in which a slight variation in porosity gives rise to large variations in CO2-saturation distribution in the core. High-resolution numerical results indicated that accurate representation of capillary pressure at small scales was critical. Residual brine saturation and the subsequent shift in the relative permeability curves showed a significant impact on final CO2 distribution in the core.

How Naturally Adsorbed Material on Minerals Affects Low Salinity Enhanced Oil Recovery

Laboratory core flood and field scale tests have demonstrated that about 5 to 40% more oil can be released from sandstone reservoirs by injecting low salinity water, rather than high salinity fluids such as seawater or formation water. The effect has been explained by a change in wettability of the minerals that form the pore wall, as a result of the decrease in divalent cation concentration. Using X-ray photoelectron spectroscopy, we have demonstrated that even for solvent cleaned core samples, mineral surfaces retain a significant quantity of carbon containing material. Thus, pore wall wettability is more likely dominated by tightly adsorbed organic material than by the character of the underlying minerals. To test this hypothesis, we used the chemical force mapping (CFM) mode of atomic force microscopy (AFM) to directly measure adhesion forces on individual quartz grains that were plucked from core plugs. We functionalized AFM tips with model oil compounds so they would represent tiny oil droplets, and we measured their ability to adhere to surfaces as salinity changed. We examined grains from a sandstone core plug that had been cut into segments, which had been stored in kerosene or solvent cleaned. On all samples, surfaces were more oil wet (higher adhesion) in artificial seawater (ASW; 35,600 ppm) than in ASW diluted with ultrapure deionized water to ∼1,500 ppm. XPS demonstrated that solvent cleaned surfaces had less adsorbed organic material than the kerosene stored sample. AFM measurements showed that the low salinity effect, namely the change in adhesion caused by decreasing salinity, was twice as high on kerosene stored samples as on solvent cleaned surfaces. The organic material that is adsorbed on the pore surfaces in the preserved sandstone offer very sticky anchor points for adhering oil molecules. This suggests that in reservoirs, even hydrophilic minerals located at the pore-fluid interface have tightly adhering hydrocarbons and the low salinity response depends on the behavior of this adsorbed material.

Critical review of low-salinity waterflooding

It was observed that higher oil recovery could be obtained when low-salinity (LS) water flooded a core of high-salinity initial water about 15 years ago. Such low-salinity waterflooding benefit or effect has drawn the oil industry attention since then. In the recent years, many researchers conducted laboratory corefloods, and several companies carried field tests. The objectives of these efforts were (1) to conform the benefits and (2) find the mechanisms of such benefit. Although most of the results confirmed the positive effect, some results showed no benefit. Many mechanisms have been proposed, but there is no consensus of the dominant mechanism(s). The oil industry is continuing the effort to discover the effect. This paper is to provide a critical review of the results and to summarize the achievements of the industry׳s effort. This paper aims to provide the status of the art. The information provided in this paper hopefully will help to speed up our further efforts to explore this effect. The following contents are reviewed: (1) history of low-salinity waterflooding; (2) laboratory observations; (3) field observations; (4) working conditions of low-salinity effect; (5) mechanisms of low-salinity waterflooding; and (6) simulation of low-salinity waterflooding. In this paper, the mechanisms proposed in the literature and their validity are discussed. • Provide a comprehensive review of lab results, field observation and all proposed mechanisms. • Discuss the validity of each mechanism. • Provide the personal view of possible effects of low-salinity waterflooding in real field-scale.

Reliable Determination of Any Water Content of Bitumen and Vacuum Residua. Applications and Validation by Comparison with Known Methodologies

The present study shows how water analysis of bitumen samples produced during in situ combustion or solvent/steam laboratory core flooding experiments is a requisite for a comprehensive understanding of the studied processes. The conceived tetrahydrofuran based Karl Fischer titration technique from a previous study was validated and found advantageous for the purpose, when compared with known azeotropic distillation or nuclear magnetic resonance methodologies.

The use of polymer-gel solutions for remediation of potential CO2 leakage from storage reservoirs

Abstract A polymer-gel based on Polyacylamide with Chromium as cross-linker was used and studied in order to ascertain its rheological characteristics at various concentrations of polymer over a range of temperatures and salinities representative of the subsurface conditions. Core flood experiments were carried out on a high permeability sandstone and fractured marble core samples to investigate the flow characteristics of the polymer-gel in porous/fractured media. Laboratory core-floods revealed significant reduction in permeability with different concentrations of polymer-gel in the injected water. Similar results were obtained for the fractured core wherein a permeability reduction of 90% was noted, demonstrating the suitability of the system for possible remediation of CO 2 leakage through the caprock. Results from reservoir simulations supported the feasibility of polymer-gel remediation at reservoir scale and identified the spatial extent of the leakage that can be remediated for various concentrations of polymer-gel solutions.

Gas and water relative permeability in different coals: Model match and new insights

A recently derived relative permeability model for coal reservoirs has been applied to fit the published gas–water relative permeability data for different coals from Europe, China, Australia and the U.S., which exhibit a myriad of shapes and curvatures. The two-parameter model is shown to be capable of describing a total of 32 sets of data, including those history-matched from field production and laboratory core flooding tests as well as laboratory-measured ones. The fitted values of the two model parameters, namely cleat tortuosity parameter (η) and cleat size distribution index (λ), fall in the range between 0 and 2, and 0.3 and 8.8, respectively. For the European and Chinese coals whose rank information is available, there is tentative evidence that a U shape correlation between λ and coal rank exists, whereas no discernible trend is observed for η. This U shape dependency on coal rank has also been reported for some other coal properties such as total porosity.

Permeability and relative permeability measurements for CO2‐brine system at reservoir conditions in low permeable sandstones in Svalbard

AbstractSequestration of CO2 in a saline aquifer is currently being evaluated as a possible way to handle CO2 emitted from a coal‐fueled power plant in Svalbard. The chosen reservoir is a 300‐m thick, laterally extensive, shallow marine formation of late Triassic‐mid Jurassic age, located below Longyearbyen in Svalbard. The reservoir consists of 300 m of alternating sandstone and shale and is sealed by 400 m of shale.Experimental and numerical studies have been performed to evaluate CO2 storage capacity. A total of 51 samples of core material from one well (Dh4) were collected and tested to find the potential units for CO2 injection. Analysis of the results shows that the permeability is generally less than 2 millidarcies and the capillary entry pressure is high. This poses a serious challenge with respect to achieving practical levels of injectivity and injection pressure. For further investigation, two 32‐cm‐long sandstone samples from the depth 675 m (Sample 1) and 679 m (Sample 2) were selected for laboratory core flooding experiments at reservoir conditions. This review presents the experimental protocol and detailed CO2‐brine drainage and imbibition relative permeability data for these two different samples of rock. Capillary pressure measurements and simulation of the transient process was used to support the interpolation of the experimental flooding data.Initial x‐ray computed tomography scan showed no sign of fractures inside the cores, whereas after the core flooding experiment, there were visible fractures especially in Sample 1. Scanning electron microscopy analysis showed a high proportion of diagenetic iron‐minerals in the sandstones like Fe‐chlorite, Fe‐carbonate (FeCO3), and pyrite (FeS2). A brownish output flow was seen in the sample with highest porosity and permeability. Dissolution of CO2 in the brine forms a weak acid that reacts with iron‐minerals (e.g. siderite) to form iron‐hydroxides. Severe hysteresis effects on one of the samples most likely resulted from changes in the rock composition.