Core Plugs Research Articles

High‐resolution X‐ray fluorescence profiling of hybrid event beds: Implications for sediment gravity flow behaviour and deposit structure

AbstractHybrid event beds form when turbidity currents that transport or locally acquire significant quantities of mud decelerate. The mud dampens turbulence driving flow transformations, allowing both mud and sand to settle into dense, near‐bed fluid layers and debris flows. Quantifying details of the mud distribution vertically in what are often complex tiered deposits is critical to reconstructing flow processes and explaining the diverse bed types left by mud‐bearing gravity flows. High‐resolution X‐ray fluorescence core scanning provides continuous vertical compositional profiles that can help to constrain mud distribution at sub‐millimetre scale, offering a significant improvement over discrete sampling. The approach is applied here to cores acquired from the Pennsylvanian Ross Sandstone Formation, western Ireland, where a range of hybrid event beds have been identified. Raw X‐ray fluorescence counts are calibrated against element concentrations and mineral abundances determined on coincident core plugs, with element and element log‐ratios used as proxies to track vertical changes in abundances of quartz, illite (including mica), chlorite and calcite cement. New insights include ‘stepped’ (to higher values) as opposed to ‘saw‐tooth’ vertical changes in mud content and the presence of compositional banding that would otherwise be overlooked. Hybrid event beds in basin floor sheets that arrived ahead of the prograding fan system have significantly cleaner sandy components than those in mid‐fan lobes. The latter may imply that the heads of the currents emerging from mid‐fan channels entrained significant mud immediately before they collapsed. Many of the H3 debrites are bipartite with a sandier H3a division attributed to re‐entrainment and mixing of a trailing debris or fluid mud flow (H3b) with sand left by the forward part of the flow. Hybrid event bed structure may thus partly reflect substrate interaction and mixing during deposition, and the texture of the bed divisions may not simply mirror those in the suspensions from which they formed.

The Effect of Nano Materials on Lost Circulation Control of Azkand Formation in Khabaz Oil Field

Experimental tests were carried to control lost circulation in the Khabaz oil field using different types of LCMs including Nano-materials. A closed-loop circulation system was built to simulate the process of lost circulation into formations. Two dolomite plugs were used from different depths of the formation of Azkand in Khabaz oil field. The experimentations were carried out to study the effect of different types of LCMs, cross-linked copolymer (FLOSORB CE 300 S), SiO2 NP, and Fe2O3 NP, on mud volume losses as a function of time.
 The rheological measurements of the nanoparticles-reference mud system showed that both of the SiO2 NP and Fe2O3 NP worked best at 1.2 g/l. and the closed-loop circulation system showed that SiO2 NP cured losses by 48.3% and 37.5% for core plugs 5C1 and 1C2 respectively which is better than Fe2O3 NP loss curing which was 37.9% and 31.3% for core plugs 5C1 and 1C2 respectively.
 On the other hand, FLOSORB CE 300 S- Fe2O3 NP-reference mud systems cured losses up to 69% with 0.25g/l FLOSORB CE 300 S and 79.3% with 0.5 g/l FLOSORB CE 300 S which is better than the FLOSORB CE 300 S- SiO2 NP-reference mud systems results.

An experimental approach to low cost, high-performance surfactant flooding.

Surfactant flooding plays a key role in chemical enhanced oil recovery due to its ability to reduce interfacial tension between the aqueous and oleic phases, thereby mobilizing the trapped oil droplets into a flowing oil bank which invariably reduces the amount of residual oil saturation thus accounting for additional oil recovery of about 20%. However, the cost of surfactant chemicals has made surfactant flooding less attractive. Interestingly, recent experimental studies have reported that certain local materials capable of acting as surface active agents can effectively recover residual oil. This has attracted more interest due to their low cost, availability and eco- friendly nature. This paper reviews the oil displacement efficiency of different local surfactants in comparison with synthetic surfactant. Commonly used synthetic surfactant, Sodium dodecyl sulphate (SDS) and three different local surfactants namely AlkaSurf X (a hibiscus plant extract), Palm kernel oil (Elaeis guineensis) and Moringa leaf (Moringa oleifera) was evaluated in the laboratory using various concentration in a bid to compare their performance, however only two local surfactants; Moringa leaf (Moringa oleifera) and AlkaSurf X were used as the third surfactant failed the initial compatibility test. To simulate actual formation brine, brine samples were prepared in the laboratory using sodium chloride and potassium chloride with Total dissolved solids (TDS) of 30,000 ppm. Critical micelle concentration (CMC) was calculated to ascertain the right concentration to flood with. Sandstone oil displacement experiments using core plugs with porosity values ranging from 22%-23% was carried out on medium crude oil to ascertain the effectiveness of the selected local surfactants in recovering oil. Results showed high compatibility of the brine with all the selected local surfactants. As the brine salinity increased, the pH of the surfactant concentration increased. In line with the results obtained from the CMC plot, the synthetic surfactant performed best at 0.2 wt.% while the local surfactants performed best at a higher concentration of 0.4 wt%. Of the two local surfactants, AlkaSurf X gave the highest additional recovery of 22.7% OOIP while the synthetic surfactant gave an additional recovery of 20% OOIP. This study underpins the oil displacement efficiency of these local surfactants. Moreover, Alkasurf X can be considered as a novel, low-cost, high performing surfactant capable of enhancing oil recovery.

The effectiveness of low salinity waterflooding in naturally fractured reservoirs

Low Salinity (LoSal) waterflooding is a technique which promises to improve and enhance oil recovery. The method has been studied widely in the laboratories using various core plug samples of sandstones and carbonates. Most of the experimental outcomes have demonstrated the possibility of recovery increment in conventional reservoirs. Meanwhile, it is rare to find a discussion in these experiments about the effectiveness of LoSal waterflooding in naturally fractured reservoirs. In this paper, we investigate the potential benefits in fractured reservoirs using simulations.It is often reported from coreflood experiments that LoSal injection has the ability to alter the rock wettability and reduce residual oil saturations through chemical and physical interactions between the rock-oil-water system. Based on the published work, we have calculated relative permeability curves to represent the flow in regions flooded with LoSal water. This includes a qualitative representation of uncertainty. In this sense, the relative permeabilities are a proxy for any physical and chemical mechanisms which are not explicitly represented. The newly generated flow curves were applied to simulate LoSal waterflooding using a fine-scale model and a field scale model based on a fractured reservoir from the Middle East.The simulation results underline the benefits of LoSal whereby the oil recovery from fractured reservoirs can be increased. An additional benefit is the control of water production. The fine-scale modelling has provided an in-depth analysis and accurate estimation of the oil recovery without modelling artefacts or limitations, where an increment of (12–14)% of the Stock Tank Oil Initially In Place (STOIIP) were obtained under secondary and tertiary recovery scheme, respectively. The investigated scenarios demonstrated a sensitivity to the newly generated flow curves and how they affect the ultimate oil recovery. However, for the field scale model, a higher oil production rate has maintained during LoSal waterflooding up to 32 K BPD by the end of year fourteen compared with 25 K BPD in case of high salinity scenario, besides a reduction in the produced water by 35.7%. Therefore, the effectiveness of LoSal brine required a longer time frame to observe the improvements in the oil displacement or sweep efficiency.

The Effect of Clay Content on the Spin-Spin NMR Relaxation Time Measured in Porous Media.

Clays, hydrous aluminous phyllosilicates, have a significant impact on the interpretation of physical measurements and properties of porous media. In particular, the presence of paramagnetic and/or ferromagnetic ions like iron, nickel, and magnesium in clays can complicate the analysis of nuclear magnetic resonance (NMR) data for porous media characterization. This is due to the internal magnetic field gradient induced by the clay minerals. In this study, we aim to investigate the impact of clay content on spin–spin relaxation time (T2), which is strongly influenced by the pore surface chemistry. Seven rock core plugs, characterized with variable clay content, were used for this purpose. The clay mineralogy and volume were determined by means of quantitative evaluation of minerals by scanning electron microscopy (QEMSCAN). The T2 relaxation time was measured using a Carr–Purcell–Meiboom–Gill (CPMG) sequence with variable echo spacing (TE). The maximum percentage difference in dominant T2 values (MRDT2) between shortest and longest echo spacing was subsequently correlated with clay content obtained from QEMSCAN. Our results show that the reduction in T2 distribution with increasing echo time TE is more significant in samples characterized by higher clay contents. The MRDT2 was found to be strongly correlated with clay content. An analytical equation is presented expressing MRDT2 as a function of clay content providing a quick and non-destructive approach for clay content estimation. Moreover, the MRDT2–clay content relationship showed a nonlinear behavior: MRDT2 increases drastically as the clay content increases up to 15%, beyond which the rate of MRDT2 change with clay content diminishes. This behavior could be attributed to the clay distribution. At higher clay contents (above 15%), it is more likely for clay to form clusters (structural clays), which will not significantly increase the clay surface in contact with the pore fluid. Further, experimental data suggests that ignoring the impact of clay on internal magnetic gradients and T2 signal may result in considerable underestimation of the actual pore size distribution.

Brine composition effect on the oil recovery in carbonate oil reservoirs: A comprehensive experimental and CFD simulation study

In order to understand the potential role of divalent ions involved in smart water, fluid-fluid and rock-fluid interactions are studied through contact angle and interfacial tension (IFT) measurements. Then, the suitable brines in changing contact angle and IFT are brought into measurement with spontaneous imbibition experiments to evaluate the co-impact of fluid-fluid and rock-fluid interactions. The results show the importance of SO42− ions during smart water injection as removing them from the injection water leads to a sharp drop in ultimate oil recovery. Accordingly, when the concentration of SO42− within the injection water increases four times, 10% ultimate oil recovery is recovered. Furthermore, the spontaneous imbibition measurements exhibit the higher ultimate oil recovery from the neutrally-wet core plugs more rather than the strong water-wet plugs. Further elaborating about the effect of wettability on the pore-scale displacement of oil by injection water is conducted through Computational Fluid Dynamics (CFD) modelling. The results confirm that the lowest residual oil saturation is achieved in the model with neutral wettability state as well as the highest oil recovery which is in line with the piston-like displacement in the neutral wet rock medium.

Effect of Mineral Composition on Transverse Relaxation Time Distributions and MR Imaging of Tight Rocks from Offshore Ireland

In this paper, we investigate the effect of magnetic field strength on the transverse relaxation time constant (T2) in six distinct core plugs from four different rock types (three sandstones, one basalt, one volcanic tuff and one siltstone), retrieved from offshore Ireland. The CPMG pulse-sequence was used at two different magnetic field strengths: high-field at 4.70 T and low-field at 0.28 T. Axial images of the core plugs were also acquired with the RAREst sequence at high magnetic field strength. Thin-sections of the core plugs were prepared for optical imaging and SEM analysis, and provided qualitative information on the porosity and quantification of the elemental composition of the rock material. The content of iron varied from 4 wt. % to close to zero in the rock samples. Nevertheless, the effective T2 distributions obtained at low-field were used to successfully predict the porosity of the core plugs. Severe signal attenuations from internal magnetic gradients resulted in an underestimation of the porosity at high-field. No definitive trend was identified on the evolution of discrete relaxation time components between magnetic field strengths. The low-field measurements demonstrate that NMR is a powerful quantitative tool for petrophysical rock analysis as compared to thin-section analysis. The results of this study are of interest to the research community who characterizes natural gas hydrates in tight heterogeneous core plugs, and who typically relies on MR imaging to distinguish between solid hydrates and fluid phases. It further exemplifies the importance of selecting appropriate magnetic field strengths when employing NMR/MRI for porosity calculation in tight rock.

Effect of Pressure on Imbibition in Shale Oil Reservoirs with Wettability Considered

Recent studies indicate that there is a great potential for enhanced oil recovery in shale oil reservoirs by altering the matrix wetness to induce spontaneous imbibition. The most common method is to add surfactant additives in fracturing fluid during multistage hydraulic fracturing operation. This imbibition process has complex pressure systems involved such as reservoir pore pressure, wellbore hydrostatic pressure, and surface pumping pressure. Without the wells being soaked intentionally, this pressurized state may be sustained for more than a month before flowback. Therefore, it is important to study the effect of pressure on the imbibition-induced oil recovery enhancement and its mechanism. In this study, we conducted forced imbibition tests on core plugs of unconventional sandstone, carbonate, and shale with different wettabilities. The applied pressures were 1000, 2000, 3000, 4000, and 5000 psi, and the results were compared to those of spontaneous imbibition under atmospheric pressure. Experimental results were used further in the numerical simulation study. The results manifested that a more water-wet state is still essential to improve the oil recovery regardless of the soaking pressure. When the rock is oil-wet, higher soaking pressure does not further worsen imbibition because of the minimal negative capillary pressure when oil saturation is high. However, when the rock is water-wet, the soaking pressures can be adverse to the imbibition in shale formations because of a longer pressure transient time which is against the capillary force. Dimensionless pressure (pD) is defined in this study to quantitatively determine the extent of imbibition inhibition during the forced imbibition. This observation indicated that in tight reservoirs, a higher soaking pressure will obtain less oil recovery from imbibition than that of lower soaking pressure cases at a given time.

Pore Structure Changes Occur During CO2 Injection into Carbonate Reservoirs

Observations and modeling studies have shown that during CO2 injection into underground carbonate reservoirs, the dissolution of CO2 into formation water forms acidic brine, leading to fluid-rock interactions that can significantly impact the hydraulic properties of the host formation. However, the impacts of these interactions on the pore structure and macroscopic flow properties of host rock are poorly characterized both for the near-wellbore region and deeper into the reservoir. Little attention has been given to the influence of pressure drop from the near-wellbore region to reservoir body on disturbing the ionic equilibrium in the CO2-saturated brine and consequent mineral precipitation. In this paper, we present the results of a novel experimental procedure designed to address these issues in carbonate reservoirs. We injected CO2-saturated brine into a composite core made of two matching grainstone carbonate core plugs with a tight disk placed between them to create a pressure profile of around 250 psi resembling that prevailing in reservoirs during CO2 injection. We investigated the impacts of fluid-rock interactions at pore and continuum scale using medical X-ray CT, nuclear magnetic resonance, and scanning electron microscopy. We found that strong calcite dissolution occurs near to the injection point, which leads to an increase in primary intergranular porosity and permeability of the near injection region, and ultimately to wormhole formation. The strong heterogeneous dissolution of calcite grains leads to the formation of intra-granular micro-pores. At later stages of the dissolution, the internal regions of ooids become accessible to the carbonated brine, leading to the formation of moldic porosity. At distances far from the injection point, we observed minimal or no change in pore structure, pore roughness, pore populations, and rock hydraulic properties. The pressure drop of 250 psi slightly disturbed the chemical equilibrium of the system, which led to minor precipitation of sub-micron sized calcite crystals but due to the large pore throats of the rock, these deposits had no measurable impact on rock permeability. The trial illustrates that the new procedure is valuable for investigating fluid-rock interactions by reproducing the geochemical consequences of relatively steep pore pressure gradients during CO2 injection.

Simulation study of relative permeability and the dynamic capillarity of waterflooding in tight oil reservoirs

Relative permeability (kr) and the capillary pressure (Pc) are the central key elements defining the multiphase fluids flow behavior in the porous media. However, the dynamic capillarity should consider the dynamic relative permeability and the dynamic capillary pressure while performing waterflooding process in extremely low permeable formations. In order to improve the oil production, the advanced horizontal well drilling along with multiple hydraulic fracturing is generally instigated to penetrate the unconventional resources. The aim of this study is to consider the dynamic capillarity in a commercial reservoir simulation, while utilizing the data gained from the dynamic and steady experiments of the relative permeability and the capillary pressure impacts during waterflooding process in the core plugs of unconventional tight oil reservoirs. The commercial reservoir simulation conducted sensitivity analyses using Computer Modeling Group simulator. The outcomes show that the well production of the reservoir is overestimated while implementing steady data for forecasting due to which the oil saturation decreases more equally and further rapidly. Additionally, the forecast of the well production estimated to breakthrough sooner. However, neglecting the dynamic capillarity causes a huge breakthrough of water influx. Therefore, the core objective of this study is to probe the consequences of taking into consideration the dynamic capillarity in ultra-low permeable formations while giving an alternative perspective to forecast the production of the hydraulically fractured unconventional tight oil reservoirs.

Characterization of Pseudomonas sp. TMB2 produced rhamnolipids for ex-situ microbial enhanced oil recovery.

The present study describes the ex-situ production of a biosurfactant by Pseudomonas sp. TMB2 for its potential application in enhancing oil recovery. The physicochemical parameters such as temperature and pH were optimized as 30°C and 7.2, respectively, for their maximum laboratory scale production in mineral salt medium containing glucose and sodium nitrate as best carbon and nitrogen sources. The surface activity of the resulting culture broth was declined from 71.9 to 33.4mN/m having the highest emulsification activity against kerosene oil. The extracted biosurfactant was characterized chemically as glycolipid by Fourier-transform infrared spectroscopy and 1H and 13C nuclear magnetic resonance spectroscopy analyses. The presence of mono-rhamnolipids (Rha-C8:2, Rha-C10, Rha-C10-C10, and Rha-C10-C12:1) and di-rhamnolipids (Rha-Rha-C12-C10, Rha-Rha-C10-C10, and Rha-Rha-C10-C12:1) congeners were determined by liquid chromatography-mass spectroscopy analysis. The thermostability and degradation pattern of the candidate biosurfactant were tested by thermogravimetry assay and differential scanning calorimetry studies for its suitability in ex-situ oil recovery technology. The rhamnolipid based slug, prepared in 4000ppm brine solution reduced the interfacial tension between liquid paraffin oil and aqueous solution to 0.8mN/m from 39.1mN/m at critical micelle concentration of 120mg/L. The flooding test was performed using conventional core plugs belonging to oil producing horizons of Upper Assam Basin and recovered 16.7% of original oil in place after secondary brine flooding with microscopic displacement efficiency of 27.11%.

Experimental Investigation of the Dependence of Accessible Porosity and Methane Sorption Capacity of Carbonaceous Shales on Particle Size

Crushing and grinding of carbonaceous shale samples is likely to enhance the accessibility of pores and embedded organic matter as compared to the intact rock. This may lead to an overestimation of the total (volume and sorptive) gas storage capacity. In order to investigate the importance of these effects we have measured unconfined apparent grain densities (helium pycnometry) and methane sorption capacities (high-pressure methane excess sorption) of four carbonaceous shales (Cambro-Ordovician Alum Shale, Jurassic Kimmeridge Clay, Jurassic/Cretaceous Bazhenov Shale, and Late Cretaceous Eagle Ford Shale) as a function of particle size. Measurements were first conducted on 38 mm diameter core plugs, which then were crushed and milled to successively smaller particle sizes (<10 mm, <2 mm, <64 μm, and <1 μm). Apparent grain densities of the smallest particle fractions of the Alum, Bazhenov and Kimmeridge samples were consistently higher by 0.5 to 1% than apparent grain densities of the original sample plugs. Methane excess sorption capacity increased significantly for particle sizes <64 μm for the Alum and <1 μm for the Bazhenov and Kimmeridge samples while no significant changes upon grinding were observed for the Eagle Ford Shale. For the Bazhenov Shale, the apparent grain density increased slightly from 2.446 g/cm3 to 2.450 g/cm3 upon particle size reduction from <64 μm to <1 μm while the maximum sorption capacity (“Langmuir volume”) increased substantially from 0.11 mmol/g to 0.19 mmol/g. Similarly, for the Kimmeridge Clay and Alum Shale, a slight increase of the apparent grain density from 1.546 g/cm3 to 1.552 g/cm3 and from 2.362 g/cm3 to 2.385 g/cm3, respectively, was accompanied by increases in sorption capacity from 0.37 mmol/g to 0.45 mmol/g and from 0.14 mmol/g to 0.185 mmol/g, respectively. The increase in sorption capacity indicates an opening of a considerable amount of micropores with large internal surface area upon physical disruption of the rock fabric and/or removal of included fluids. It may also be due to increased swelling abilities of clay minerals and organic matter upon destruction of the stabilizing rock fabric with decreasing particle size. Grain density and sorption isotherms measured on small particle sizes are likely to overestimate the gas storage capacities and the amounts of producible gas-in-place since under field conditions (largely undisrupted rock fabric), significant portions of this storage capacity are essentially inaccessible. Poor interconnectivity of the pore system and slow, diffusion-controlled transport will massively retard gas production. Based on these findings, particle sizes >64 μm should be used for porosity and sorption measurements because they are more likely to retain the properties of the rock fabric in terms of accessible pore volume and sorptive storage capacity.

Impact of rock properties and wettability on Tertiary-CO2 flooding in a fractured composite chalk reservoir

This study presents the experimental and numerical evaluation of tertiary-CO2 flooding (CF) using reservoir and outcrop composite chalk at reservoir conditions. We were able to reproduce the results of composite core flooding experiment and our findings show the considerable effect of rock properties and wettability on the tertiary-CO2 flooding.In our experiments, we place the composite reservoir chalk core vertically in the core-holder with the total length of 45 cm and average diameter of 3.74 cm. The composite core consists of six core plugs of 7.5 cm each and include a centralized axial hole that represents the single fracture with the diameter of 0.6 cm. The whole core plugs are sampled from the reservoir formation in North-Sea-Chalk-Field (NSCF) and are saturated with NSCF stock tank oil (STO) and synthetic connate water. Once reservoir conditions are established, the sea water is injected from the bottom of the core holder and the STO is produced from the top. After no additional produced oil is observed, water flooding (WF) is stopped and CO2 is then injected from the top and the hydrocarbon streams are produced from the bottom of the fracture. The whole core flooding is operated at constant reservoir conditions of 258 bara and 110 °C, representative of NSCF reservoir conditions. Two different chalks, one from the reservoir formation (Exp-3C) and the other from outcrop (Exp-2C) are used in this study to investigate the effect of wettability during tertiary CO2 flooding. A comprehensive compositional numerical simulation with a tuned equation of state (EOS) was developed to model the experiments. Best match for the WF experiments was achieved mainly through tuning the oil-water capillary pressure and reducing the oil relative permeability data. Although the final tuned capillary pressure and relative permeability data were different, we observe similar water saturation at the end WF experiments for Exp-3C and Exp-2C.The tertiary CF lab results were reproduced by numerical model mainly by tuning the multi-component diffusion coefficients. The produced water during CF was successfully modeled by taking the hysteresis effect into account in water-oil capillary pressure data. We also observe that although the final water saturation at the end of WF is comparable, performance of tertiary CO2 flooding for each experiment is different. The reservoir chalk experiment shows higher oil recovery during the tertiary CO2 injection.

Changes in retained fracturing fluid properties and their effect on shale mechanical properties

To understand the fluid-shale interactions and the mechanisms that produce cracks during the retention of the fracturing fluid. This paper details experiments performed in shale particle immersion and core plug imbibition, and it investigates changes in fluid properties during a shale well shut-in period at the Longmaxi formation in Southeast Chongqing, China. The results indicate that soluble salts in a shale formation are dissolved during fracturing fluid retention in a shale reservoir, causing the salinity and pH of the fracturing fluid to increase significantly and eventually resulting in the formation of a weakly alkaline solution. Furthermore, fracturing fluid retention significantly reduces the mechanical strength of shale. In the experiments, the elasticity modulus and Poisson's ratio of the shale decreased by 85% and 54%, respectively, which was immersed in the fracturing fluid for seven days. Two types of forces, repulsive hydration and electric double-layer repulsion, are shown to be the main factors that lead to the formation of a large number of microcracks. The repulsive hydration pressure force is in a short range, operating over only a few nanometers, while the electric double-layer repulsion force operates over a long distance and can act between clay mineral slices. As the concentration of the solution increases, the double-layer repulsive force increases, though the range over which it acts becomes shorter. The increase in the OH− concentration of the solution also accelerates crack propagation. These conclusions are conducive to developing reasonable rules for fracturing fluid flowback in shale gas wells.

The effects of stress and fluid on the anisotropy of reservoir rock: case study of a sandstone from the harvey 3 CCS site, Western Australia

In rock physics one of the important purposes of the determination of P- and S-wave velocities is to obtain the elastic constants and anisotropy parameters. This method is standardised in American Society for Testing and Materials (ASTM) by a standard D2845-95. The most challenging yet important part of these experiments is picking the first arrivals correctly and consistently. A sharp, clean first arrival of a wave is not always possible, especially when testing dry, porous sandstones at low pressures. The signal transmitted through such samples is weak due to a high damping effect, and picking the first break introduces uncertainties. Harvey sandstone is a sample type with high porosity and, therefore, some degree of anisotropy is expected. In order to study the anisotropy parameters of the Harvey 3 sandstone which belongs to Lesuer- Wonnerup Member of the Yalgorup Member, three core plugs in directions of horizontal, vertical and diagonal, were experimentally investigated. The laboratory measurements on three different samples which are cut at three different directions with regards to the base deposition system enabled us to calculate the anisotropy parameters using a standard acoustic equipment while applying stress. We concluded that Harvey 3 poses a more complex symmetry axis of anisotropy, and no sign of low-grade anisotropy was observed through the experimental data. To study the anisotropy degree of the Harvey 3 sandstone, a pressure cell, pore fluid injection pump, and ultrasonic system (consisting of P- and S-wave transducers, oscilloscope and pulser/receiver) were used to record the elastic waves passing through the samples. The specimens were fully saturated inside the pressure cell using vacuum injection for the best possible comparison of dry and saturated status. The results confirmed that the sample is far from weak anisotropy and possesses more axes of symmetries than simple layering anisotropy due to the pore orientation and distribution in the matrix of the background rock. The study also confirms that the anisotropy degree decreases under full compaction and full saturation, and the Harvey 3 anisotropy becomes elliptical when it’s fully saturated. Large, stress-dependent changes in the ultrasonic velocities for porous media were observed in this experimental study, which confirms the usefulness of such studies in examining the inner structure change process.

Experimental investigation and theoretical modeling of stress-dependent permeability in naturally fractured tight gas reservoir

Stress-dependent permeability (SDP) of naturally fractured tight gas reservoir (NFTGR) has drawn considerable attention in recent decades. The SDP of natural fracture (NF) is quite different from that of the rock matrix (RM) due to the variance NF width and NF filling degree. The SDP of naturally fractures can be obtained by conducting permeability measurement experiments on naturally fractured core plugs (NFCP). However, it is usually impossible to obtain downhole NFCPs due to economic and technical limitations. Our research group obtained various types of naturally fractured downhole core plugs from a NFTGR (Tarim filed, China) and make it possible to investigate the effect of NFs on SDP. The NF types of the downhole core plugs include RM core plug (RMCP), unpenetrated-ring fractured core plug (URFCP), penetrated-vertical fractured core plug (PVFCP), penetrated-incline fractured core plug (PIFCP), unpenetrated-U-type fractured core plug (UUFCP), and multiple fractured core plug (MFCP). We conducted SDP experiments through the application of pressure-pulse-decay (PPD) method. Results showed that the initial permeability of RMCP and MFCP were higher than that of others, and the permeability vanished stress of them were also highest, indicating that the flow resistance of RMCP and MFCP were lower than those of others. It is also shown that the degree of permeability stress-dependent (DPSD) varied from NF types. A modified exponential permeability model was derived to evaluate DPSD of natural fractured core plugs. Two parameters (γσeff and γσeff') were used to describe the DSDP in NFTGR, and the range of which were obtained from the experimental data by regression analysis. The reasonable γσeff and γσeff' range of NFCP were also proposed in this paper. Sensitivity analysis showed that the influence γσeff' on SDP was more significant than that of γσeff. The proposed model can be integrated to reservoir simulators and help to improve of oil and gas production prediction accuracy in NFTGRs.

An Improved Hydraulic Fracturing Treatment for Stimulating Tight Organic-Rich Carbonate Reservoirs

Summary Hydraulic fracturing has been widely used in stimulating tight carbonate reservoirs to improve oil and gas production. Improving and maintaining the connectivity between the natural and induced microfractures in the far-field and the primary fracture networks are essential to enhancing the well production rate because these natural and induced unpropped microfractures tend to close after the release of hydraulic pressure during production. This paper provides a conceptual approach for an improved hydraulic fracturing treatment to enhance the well productivity by minimizing the closure of the microfractures in tight carbonate reservoirs and enlarging the fracture aperture. The proposed improved fracturing treatment was to use the mixture of the delayed acid-generating materials along with microproppants in the pad/prepad fluids during the engineering process. The microproppants were used to support the opening of natural or newly induced microfractures. The delayed acid-generating materials were used in this strategy to enlarge the flow pathways within microfractures owing to degradation introduced under elevated temperatures and interaction with the calcite formation. The feasibility of the proposed approach is evaluated by a series of the proof-of-concept laboratory coreflood experiments and numerical modeling results. First, one series of experiments (Experiments 1–3) was designed to investigate the depth of the voids on the fracture surface generated by the solid delayed acid-generating materials under different flow rates of the treatment fluids and different temperatures. This set of tests was conducted on a core plug assembly that was composed of half-core Eagle Ford Sample, half-core hastelloy core plug, and a mixture of solid delayed acid-generating materials [polyglycolic acid (PGA)] along with small-sized proppants sandwiched by two half-cores. Surface profilometer was used to quantify the surface-etched profile before and after coreflood experiments. Test results have shown that PGA materials were able to create voids or dimples on the fracture faces by their degradation under elevated temperature and the chemical reaction between the generated weak acid and the calcite-rich formation. The depth of the voids generated is related to the treatment temperature and the flow rate of the treatment fluids. Experiment 4 was conducted using two half-core splits to quantify the improvement factor of the core permeability due to the treatment with mixed sand and PGA materials. Simulations of fluid flow through proppant assembly (inside of the microfractures) using the discrete element method (DEM)–lattice Boltzmann method (LBM) coupling approach for three different scenarios (14 cases in total) were further conducted to evaluate the fracture permeability and conductivity changes under different situations such as various gaps between proppant particulates and different depths of voids generated on fracture faces: (1) fluid flow in a microfracture without proppant, (2) fluid flow in a microfracture with small-sized proppants, and (3) fluid flow in a microfracture supported by small-sized proppants and generated voids on the fracture walls. The simulation results show that with proppant support (Scenario 2), the microfracture permeability can be increased by tens to hundreds of times in comparison to Scenario 1, depending on the gaps between proppant particles. The permeability of proppant-supported microfracture (Scenario 3) can be further enhanced by the cavities created by the reactions between the generated acid and calcite formation. This work provides experimental evidence that using the mixture of the solid delayed acid-generating materials along with microproppants or small-sized proppants in stimulating tight carbonate reservoirs in the pad/prepad fluids during the engineering process may be able to effectively improve and sustain permeability of flow pathways from microfractures (either natural or induced). These findings will be beneficial to the development of an improved hydraulic fracturing treatment for stimulating tight organic-rich carbonate reservoirs.

Laboratory core investigations of sandstone-hosted uranium for in situ recovery

ABSTRACTSeveral core plugs from a 1243 m-deep borehole penetrating the Westwater Canyon Member of the Morrison Formation in New Mexico (USA) have been investigated by various petrophysical methods to evaluate the potential of extracting deeply buried sandstone-hosted uranium deposits by in situ recovery (ISR). Petrophysics and mineralization patterns of the host rock in the target aquifer are crucial parameters for ISR amenability and were determined according to the ISR feasibility criteria. Mineralogical investigations revealed a secondary uranium mineralization mainly coating the silica grains of the arkosic sandstone and some interstitial pore fillings. The differences between mineralized and non-mineralized sandstone plugs are highlighted by nuclear magnetic resonance (NMR), X-ray microcomputed tomography, and spectral induced polarization (SIP). The NMR results show a doubling of the clay- and capillary-bound water and a decease of free-fluid porosity of mineralized samples. A correlation of mineralization grade and polarization is observed through the SIP investigations.

Impact of water saturation on the elastic anisotropy of the Whitby Mudstone, United Kingdom

Mudstones are often anisotropic, which complicates depth conversion in seismic exploration and monitoring subsurface reservoirs during injection or production. In addition, the physical and mechanical properties of mudstones are highly sensitive to their water content. The elastic anisotropy of mudstones is not well understood because of their complex nature and the lack of laboratory experiments performed on well-preserved samples. Triaxial deformation tests were performed on mudstone core plugs to investigate the impact of water saturation on the elastic anisotropy of the Whitby Mudstone (United Kingdom). The mechanical and physical properties of the Whitby Mudstone were estimated from stress-strain and ultrasonic wave velocity data obtained on core plugs with different water saturations under isotropic and anisotropic stress conditions. The Whitby Mudstone has extremely high intrinsic elastic anisotropy (0.3–0.4) due to its composition and lamination. This elastic anisotropy increases with decreasing water content. There are three competing mechanisms that play a key role in the anisotropy increase due to dehydration such as (1) density contrast in the pore space (i.e., the presence of purely brine or a mixture of brine and air in the pore space), (2) formation of dehydration fractures, and (3) frame stiffening. Increasing the mean effective stress leads to a decrease in Thomsen’s anisotropy parameters [Formula: see text] and [Formula: see text] because of the closure of defects, such as natural and dehydration fractures, and the formation of stress-induced fractures. The relationship between the wavefront anellipticity factor [Formula: see text] and the mean effective stress is nonmonotonic and can be related to the onset of inelastic deformation.

Inverted bucket centrifugation with fluorinated oils and its applications to T2 cut-offs

Hydrocarbon reservoirs with a large column height as well as tight gas rocks require a large range of capillary pressures to describe the saturation of fluids present in these formations. While mercury injection capillary pressure (MICP) can achieve high equivalent capillary pressures, the tests are destructive to the core plugs. Centrifuge techniques have gained in popularity since they are faster than the porous plate technique, but they are limited in the achievable pressure range. Here, we propose the use of fluorinated oils to extend the achievable capillary pressure of the air-brine centrifuge technique by a factor of two. We use Fluorinert FC-70 in an inverted bucket configuration which doubles the radius of rotation and keeps the density contrast comparable to an air-brine system. Furthermore, we show the application to NMR T2 cut-off determination as a function of capillary pressure. Since Fluorinert does not contain any hydrogen, there is no signal overlapping with the brine in the core plugs. Furthermore, in the inverted bucket configuration, the outlet face of the plug is not in contact with a drainage surface so that the Hassler-Brunner boundary condition of Pc = 0 is satisfied. Additionally, the method allows the storage under a liquid Fluorinert phase, which prevents evaporation and significantly extends the available time for NMR measurements at low water saturations.