Implication of heterogeneities on core porosity measurements

Heterogeneities within core samples affect the accuracy of the laboratory measured core plug interconnected porosity. The laboratory measures the volume averaged porosity of the interconnected pores, . For homogeneous cores this is the correct porosity ± any experimental error. However for heterogeneous cores when any embedded material (unknown or ignored) has a differing porosity, ϕi, to that of the containing outer shell, ϕo, there will be increased uncertainty. We show that the difference between the measured volume averaged porosity, , and the porosity of the outer shell of the core, ϕo can be quantified by our Heterogeneity Factor, H. H is defined as ( - ϕo)/ϕo and given by H = F(R-1), where F is the ratio of the bulk volume of the embedded material to the total core bulk volume (measured), VBi/VBm, and R is the ratio of the embedded and the host outer porosity, ϕi/ϕo. The core plug homogeneous model can create increased error bounds in porosity for heterogeneous plugs. When H is zero there is no error in the porosity measurement due to heterogeneity, but when H≠ 0 then the differences can be significant and increases the experimental error bound. We present graphs for relevant industry scenarios to demonstrate the effect of any inclusions in the measured porosity. We find that when F is ∼0.1 i.e., inner included porosity is 10% of bulk volume, the relative error between and ϕo can reach ∼30% and even larger differences when F > 0.1. We then give a real example from a faulted vuggy outcrop carbonate which demonstrates extra porosity uncertainties, even for a very small vug. Finally we discuss the possible effect of embedded clay intrusions emitting adsorbed gas on grain/pore volume determinations of porosity using gas expansion, a common laboratory method of porosity determination. Appreciation of core heterogeneity on the precision of the laboratory porosity measurements is essential to improve the confidence in the error bounds for the quality control of laboratory core porosity measurements, and of the porosity distribution frequency for inputs to statistical methods such as Monte Carlo analysis for oil-in-place estimations, STOIIP

Permeability of fault rocks in siliciclastic reservoirs: Recent advances

It is common practice to create geologically realistic production simulation models of fault compartmentalized reservoirs. Data on fault rock properties are required, to calculate transmissibility multipliers that are incorporated into these models, to take into account the impact of fault rocks on fluid flow. Industry has generated large databases of fault rock permeability, which are commonly used for this purpose. Much of the permeability data were collected using two inappropriate laboratory practices with measurements being made at low confining pressure with distilled water as the permeant. New fault rock permeability measurements have been made at high confining pressures using formation compatible brines as the permeant. Fault permeability decreases by an average of five fold as net confining pressure is increased from that used in previous measurements (i.e. ∼70 psi) to that approaching in situ conditions (i.e. 5000 psi). On the other hand, permeability increases by around the same amount if reservoir brine is used as the permeant instead of distilled water. So overall, these two inappropriate laboratory practices used in previous studies cancel each other out meaning that legacy fault rock property data may still have value for modelling cross-fault flow in petroleum reservoirs. A poor correlation exists between clay content and fault rock permeability, which is easily explained by the application of a simple clay-sand mixing model. This emphasises the need to gather fault permeability data directly from the reservoir of interest. The cost of such studies could be significantly reduced by screening core samples using a CT scanner so that only samples that are likely to impact fluid flow are analyzed in detail. The stress dependence of fault permeability identified in this study is likely to be primarily caused by damage generated during or following coring. So it is probably not necessary to take into account the impact of stress on fault permeability in simulation models unless the faults of interest are likely to reach failure and reactivate

Nonadditivity of critical Casimir forces

In soft condensed matter physics, effective interactions often emerge due to the spatial confinement of fluctuating fields. For instance, microscopic particles dissolved in a binary liquid mixture are subject to critical Casimir forces whenever their surfaces confine the thermal fluctuations of the order parameter of the solvent close to its critical demixing point. These forces are theoretically predicted to be nonadditive on the scale set by the bulk correlation length of the fluctuations. Here we provide direct experimental evidence of this fact by reporting the measurement of the associated many-body forces. We consider three colloidal particles in optical traps and observe that the critical Casimir force exerted on one of them by the other two differs from the sum of the forces they exert separately. This three-body effect depends sensitively on the distance from the critical point and on the chemical functionalisation of the colloid surfaces

An oil-based gel system for reservoir rock permeability modification

Water production during gas and oil recovery is a major problem for the oil industry, as the average worldwide production is more than five barrels of water per barrel of oil. Among the many attempted remedies, water-based polymers and cross-linked gels are often injected into the reservoir to control excessive water production. Recently, oil-based gelant systems have been proposed which are oil-soluble. These systems react with the reservoir water to form a rigid water-based gel during the shut-in period, thereby drastically reducing the permeability of the reservoir to water. The aim of this paper is to improve the understanding of how the flow of oil and water are affected by one of the oil-based gelant systems, TMOS. The gelation behaviour and gel characteristics were studied under static and dynamic conditions. Two-dimensional transparent glass models were used to study the effect of gelant flow, and evaluate the effectiveness of the gel in modifying the oil and water permeability. The ability of the gel to modify the water flow at different flow velocities yields a velocity-dependent permeability. New insights are presented that may help reservoir and production engineers to select and design better gel treatments for a given reservoir

Corrigendum to ‘Implication of heterogeneities on core porosity measurements’

© 2018 Elsevier B.V. The authors regret that Fig 3 was incorrectly printed as a duplicate of Fig. 4. The correct Fig 3 with original caption is given here. The authors would like to apologise for any inconvenience caused. [figure-presented] Caption Fig. 3. Plot of H against ϕ i using Eq. (7), with ϕ o = 0.20. H = 0 when ϕ i = 0.20. When F = 0 there are no inclusions and thus and ϕ o will be the same (since there is no ϕ i ). At other values of ϕ i , H ≠ 0, and there could be error. At ϕ i = 0.20, H = 0 for all the F's. At H= 0.1, the dashed line, the difference between and ϕ o will be ∼10%, but below this value the assumption of core homogeneity may probably create little extra uncertainty

Flow-induced-microgel adsorption of high-molecular weight polyacrylamides

Water soluble polymers are widely used in oil and gas reservoirs and usually injected into the reservoir rocks to alter their flow properties. The rheologies of the polymer solution and their adsorption or interaction with the porous system are crucial for the success of the injection. This work aims to investigate the formation of residual polymer multilayers as a result of the flow of aqueous solutions of high-molecular-weight cationic (CPAM) and non-ionic (PAM) polyacrylamides through single, circular and rectangular capillaries.Polymer solutions in de-ionized water and weak brine were injected at different flow rates into glass capillaries of circular and rectangular cross sectional area. The adsorption energy and layer thickness on glass surfaces of these polymer solutions have been investigated by Al-Hashmi and Luckham (2010) under static conditions using colloidal force measurements. The apparent viscosity of the polymer in solution on both increasing and decreasing the shear rate are presented to indicate the thixotropic or anti-thixotropic behaviour of the solution. Also, the viscosity-time curves are presented to investigate the rheopectic behaviour of the polymer solutions.The flow CPAM in water solution through the capillaries resulted in very thick residual polymer layers, around 15 times thicker than those measured under static conditions. This solution shows both anti-thixtropic and rheopectic behaviour, which may be attributed to flow-induced-microgel formations in the bulk of the polymer solution. The same polymer solution has shown almost instantaneous adsorption from the colloidal force measurements due to electrostatic attraction of the cationic groups of the polymer to the negative glass surface. Such thick layers are not formed when CPAM in 0.34. M NaCl is used. Although it has shown strong adsorption on glass, the CPAM in 0.34. M NaCl exhibits neither anti-thixotropic nor rheopectic behaviour. Though it has shown rheopectic behaviour, the non-ionic polyacrylamide in water solution does not result in significantly thick layers, which might be due to its weak adsorption on glass.In the current study, a new mechanism is proposed to attribute the apparent formation of residual multilayer under the name of flow-induced-microgel adsorption (FIMGA). According to the new mechanism, two criteria have to be satisfied for polymer multilayer formation: the formation of sizable shear-induced-microgel structures in the bulk of the solution, and sufficiently high adsorption energy of the polymer to the solid surface. The new understanding in view of this new mechanism will contribute to more successful applications of polymers in oilfields. It will also allow faster screening of the chemicals for a specific application which may warrant different characteristics of flow and adsorption. For example, polymers used in enhanced oil recovery should have high injectivity and low adsorption. On the other hand, high adsorption and thick residual polymer layers are the key for a successful use of polymers in water shut-off in oil and gas wells