Porosity and permeability for the Berea sandstone exhibiting large interfacial tensions Lab 3 and lab 4 by Group 38

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1 Porosity and permeability for the Berea sandstone exhibiting large interfacial tensions Lab 3 and lab 4 by Group 38 Losoi, Henri Henri( a )Losoi.com Sigvathsen, Christoffer Sigvaths( a )Stud.NTNU.No March 9, Introduction The Berea sandstone core is investigated. Its color is light yellowish white. Visual inspection to other Berea cores does not reveal any noticeable difference between the rock used for this report and other Berea rocks. Berea sandstone is marketed as a sedimentary rock whose grains are predominantly sand-sized and are composed of quartz held together by silica. The relatively high porosity and permeability of Berea Sandstone makes it a good reservoir rock [1]. Permeability is investigated with 3 wt% NaCl brine and oil D60, it is not specified by which term such as moles or volume the proportion in the brine is measured. The sample is cleaned with the Soxhlet method. It removes undesirable substances in the intergranual porosity of the material such as impurities from earlier experiments. The solvent used for distillaton is apparently water, this is not totally certain because the experiment was conducted by a separate party. The distillation lasted 24 hours. The time of distillation was again confirmed by third party to be sufficient, this is not necessarily true. The solvent has no surface contact with the intragranual fluids so they are still left in the rock. After the distillation, the core was dried in an oven. The labs investigate the porosity and permeability of a sandstone. Porosity and permeability tend to correlate with each other: the deeper you go the worse they tend to become. Permeability measures the ability of a porous material to allow fluids to pass through it. This paper is only interested in flow with a single fluid so absolute permeabilities are considered. The gas permeability machine is used for permeability measurement and it uses nitrogen as a contact fluid. Klinkenberg effect is that the permeability of porous media to gases is approximately a linear function of the reciprocal pressure. We demonstrate this by calculating the Klinkenberg constant. Porosity measures the void in a material. It is defined as the ratio of the pore volume to the bulk volume of the porous 1

2 media. Porosity is measured with Helium porosimeter. The Helium porosity method is based on Boyle s law P i V i = P f V f (1) where P i is the initial pressure, V i is the inial volume, P f is the final pressure and V f is the final pressure. Unknown amount of helium gas is isothermally expanded at constant pressure to an unknown void volume. After the expansion the resulted pressure is mearused and this pressure is independent of the unknown void volume. By the ideal gas assumption the void volume can be measured with the Boyle s law (1). Helium is used for multiple reasons. Firstly it can be modelled as an ideal gas for most pressures and and temperatures of interest. Secondly helium consists of tiny molecules that can penetrate pores of the rock. Thirdly helium has low mass and hence high diffusivity which means that the helium can be used to determine the porosity of low permeable rock. The following hypotheses were given in the instructions about permeability and porosity. Hypothesis 1. The expected porosity is 10-25%. Hypothesis 2. The expected permeability is mD. Permeability in porous media can be investigated with Klinkenberg effect. Klinkenberg measurements can be made in atmospheric flow mode, or backpressure flow mode; under either constant differential pressure, or constant mass flow rate (page 373 [3]). The gas permeability regressed to 1 atmosphere between atmospheric and backpressure flow data is between 3.4% and 4.5% (page 375[3]). So Hypothesis 3. The Klinkenberg constant is between %. 2 Methods and Materials The gas permeability machine is conducted with a sleeve. This means that the confining pressure is 20.0 bar. The flow rate Q is 10ml per minute. The sandstone core has the shape of the cylinder. The stone volume is defined by Equation 2. The pore volume is defined by Equation (3) V k = V 1 V 2 (2) V p = V b V k (3) where V b = πr 2 h is the volume of the block. The measurements are summarised in Table 2. The permeability is given by Equation (4) k abs = µ fluidlq P A (4) 2

3 Figure 1: Measurements contained pressures P 1, P 2, P and Q by which the permeability was calculated with (4) and the information about the core profile. where µ fluid can be air or brine. µ air is the viscosity of air, L is the height of the block, Q is the flow and A is the area of the block. The Klinkenberg correction for the equation (4) is (5) k = 2µ airlqp i (P 2 1 P 2 2 )A (5) where the gas slippage effect is taken into account and P i is the initial pressure and here 1 bar. Viscosity is assumed to be measured at 20C, the actual room temperature can be different. Measurements are summarised in Figure 1 and Figure 2. The effective porosity is defined by (6) φ e = V p V b (6) where its result is in Table 2. Permeability can be analysed with Klinkenberg effect. This can be observed in Figure 2 and Figure 3. The Klinkenberg constant is defined by b = m k l (7) where m is the slope and k l is the intercept in the y-axis as shown in Figure 3. The slope is = so the Klinkenberg constant is b = = %. 2.1 Procedure for absolute permeability The procedure to get k abs is record sleeve P, Q, µ brine, L and A 3

4 Figure 2: Klinkenberg effect can be visualised with the reciprocal of pressure against the permeability. The reasons for this behaviour contain the ideal gas behaviour and isothermal expansion. 4

5 Figure 3: The intercept and the slope for calculating the Klinkenberg constant. plot P over time to investigate the stabilitization of pressure calculate k abs with Equation 4 (and remember to convert units to md compare k abs from the 3% NaCl with brine to the k l from the lab 3 in comparison the industry also uses the method where you vary Q inj so the plot Q versus P and the k abs is more accurate with various injection rates. Measurements. The absolute permeability for oil is 1cm cP 40.84mm 6s k absoil = 4.34bar1125.8mm 2 = m 2 = mD and for water is cP 40.84mm10ml/min k abswater = 4.34bar1125.8mm 2 = m 2 = mD where the viscosities are from Lab 1 and Lab 2 as shown in Table 1. Figure 4 shows the pressure profile over time when the pressure eventually stabilises. 5

6 Sample Kinetic Dynamic Perssure Absolute viscosity (Lab 1/2) viscosity (Lab 1/2) (Lab 4) permeability v µ P k abs (cst) (cp) (bar) (md) Salt Salt Oil Oil Table 1: Different viscosity values from Lab 1 and Lab 2. Figure 4: Perssure over time measured for Lab 4 where the pressure stabilises at 4.34 bars. The absolute permeability measurements were conducted in Lab 4. 6

7 3 Results and observations The Berea sandstone was investigated. The fluids used for investigation of visconsity are air, brine (salt water) and D60 oil. Permeability was analysed with the Klinkenberg model that formulates the flow for porous media [3]. Permeabilities did not satisfy Hypothesis 2 and Hypothesis 3. The result for the Klinkenberg constant is 2.72% which does not the satisfy Hypothesis 3. The results for the absolute permeabilities are 4.16mD and 3.51mD for salt and oil, respectively, which do not satisfy Hypothesis 2. A key assumption in determining the permeability is the steady-state Darcy flow. This assumption should not be provocated by the large interfacial tension observed in Figure 5 because the permeability was measured as a single phase system. If however the Soxhlet method did not remove the oil from the intergranual porosity, then the system was a two phase system. In the two phase system, the measured permeabilities can be lower than expected because increasing interfacial tension is known to decrease the relative permeability values at least in the case of gas and gas condensate [2]. Raynolds number, investigating viscous forces and inertial forces, should be calculated to analyse whether the flow was laminar or not. Non-Darcy flow should exhibit decreasing effective permeability when the flow rate increases [2], this is easy to experiment to investigate the flow nature. So Hypothesis 4. The Berea sandstone by Group 38 exhibits non-darcy non-steady state flow when the oil is stuck in the intergranual porosity due to high capillary forces which should demostrate itself in the permeability profiles with different flow rates. where it is possible that the Berea sandstones naturally have low permeability and/or the Soxhlet cleaning was not sufficient. The easiest way to investigate this is to redo the Soxhlet with longer cleaning time and then observe whether the permeabilities are still as low as earlier. The result for the effective porosity is 15.18%. The target range given by the teacher is 10-25%. Then again the the provider states that their cores have ambient porosities from 13% to 23% [1]. The result is closer to the lower bounds than the upper bounds, the lower boundsare associated with more poor quality reservoirs. Hypothesis 1 about porosity is satisfied. The Berea sandstones are manufactured by BereaSandStonesCores.com and they offer a range of products where permeabilities range from 19mD thru 2500mD [1]. The cores with md are usual while other cores are classified as rare [1]. Hence the measured absolute permeabilities may be incorrect or the stone is an outliner: a core with permeabilities in the range of 3-4mD should not exist from this provider. 4 Discussion and possible errors The comparison between the porosity and the permeablitity results from both tests will be discussed. The permeability and the porosity have a tendency to correlate with each 7

8 Figure 5: Bubbles observed in Lab 5 and Lab 6 mean large interfacial tensions that keep the oil on the surface of the rock and/or bad cleaning process with the Soxhlet in which case the capillary forces inside would have kept the intergranual oils more stuck where the chosen temperature, chosen solvent and cleaning time were not sufficient. The bubbles on the surface were not observed with rocks of other groups which can be seen on the background. The large interfacial tensions and the high capillary forces can block the flow of fluids inside the rock damaging the permeability. 8

9 other (one of the last chapters in [4]). The porosity value and permeability value are associated with more poor quality reservoirs: particularly the permeability values are very low. The possible errors contain The distillation temperature and the distillation time for the Soxhlet method may be insufficient to remove the intergranual materials such as impurities and fluids. The gas permeability machine had some leakages in the connectors because of unexpectedly high pressures caused by the resistance to flow, more in Figure 5. where the most dominant error and its extent are unknown. Instrumental errors are related to the fact that the profiles of the instruments were not designed to work with cores having extremely high capillary pressure. The best way to analyse this error is to repeat the experiment and make sure the connectors are tightly connected and use as low flow rate as possible not to cause the pressure to go over the measurement range or the durability of instruments. 5 Conclusion The rock is probably a bad reservoir rock. This is because of the low porosity value and low permeability value. It is not optimal for hydrocarbon flow. Typical good Berea reservoir rocks are mD according to [1] while our results are about 3-4mD for permeability while porosity values at the lower bounds i.e. near bad reservoir porosities. The bad quality of the reservoir rock is supported by the observation about bubbles forming on the top of the rock surface in Figure 5 hinting about non-darcy and/or nonsteady-state flow that requires more accurate optimization in possible drilling situation. The results are tested in standard conditions and the necessary adjusting and conversions to reservoir conditions are not done so this synthesis must be read with caution for hydrocarbon production. References [1] BereaSandStonesCores.com. Provider for the sandstones used in the experiment. url: [2] G.D. Henderson et al. The effect of velocity and interfacial tension on relative permeability of gas condensate fluids in the wellbore region. In: Journal of Petroleum Science and Engineering (1997). [3] Colin A. McPhee and Kevin G. Klinkenberg permeability measurements: problems and practical solutions. In: Edinburgh Petroleum Services Limited, UK. (1991). [4] The millennium atlas: petroleum geology of the central and northern North Sea. The Geological Society of Lonodon, Norwegian Petroleum Society, Geological Survey of Denmark and Greenland, Millennium Atlas Company Limited,

10 Cylinder core feature Value Hypothesis Description Bulk volume 45.97cc NA NA Pore volume 6.978cc NA NA Dimensions (diameter) 37.87mm NA NA Dimensions (height) 40.84mm NA NA Final porosity (effective) 15.18% 10-25% Satisfied. Final absolute permeability (salt) 4.16mD mD Not satisfied. Final absolute permeability (oil) 3.51mD mD Not satisfied. Klinkenberg constant 2.72% % Not satisfied. Table 2: Core properties contain bulk volume, dimensions, pore volume, final porosity and final absolute permeability. All measurements for permeabilities do not satisfy their hypothesis namely Hypothesis 2 and Hypothesis 3. This can be due to too large capillary forces within the rock and large interfacial tensions on the surface that result into non-darcy flow. 10