How can you test the permeability of a rock core?

Please note that testing permeability does not necessarily provide us porosity, saturation, pressure, and fluid types (is this question produced by “AI”?). Permeability is one of the intrinsic rock properties and measures the easiness/difficulties for single phase fluid, be it gas or liquid, to pass through the rock.

La pregunta esta referida al porque y creo que es muy importante su respuesta, ya que este valor es fundamental para conocer la productividad del reservorio, nuestra experiencia en reservorios lenticulares y pozos multilayer, es muy difícil tener los recursos suficientes para conocer la k en todos los pozos, pero hoy tenemos la posibilidad a través de los ensayos de presión en pozos inyectores (FOT), obtener muy buena información al respecto y así entender y reestudiar nuestros proyectos de waterflooding, optimizando no solo los modelos , sino también el barrido a los pozos productores.

Permeability (K) of a rock is a measure of its ability to allow flow of fluids through it. Hydrocarbons are trapped in the small pores within a rock and testing the K allows to understand the flow potential of a rock. When K is measured on several cores of a well and across the other wells in the field it can easily be distributed across the entire field using statistical methods. For conventional rocks (for example sandstone and limestones) the K if typically in millidarcies (mD) to Darcy range. For tight and unconventional rocks K can be in micro to nanodarcy range making flow from these rocks very difficult. For unconventional rocks testing permeability is quite difficult and a conventional K testing method doesnt even work.

Knowledge of reservoir permeability is crucial in selecting Enhanced Oil Recovery (EOR) methods, such as polymer flooding. In high-permeability reservoirs, water tends to channel through more permeable zones, leaving oil unrecovered in less permeable areas(known as channeling). Polymer flooding involves injecting a polymer solution to increase water viscosity, reducing its mobility and improving sweep efficiency. Permeability data is input into reservoir models, helping engineers simulate and optimize polymer flooding strategies for efficient oil recovery.

Permeability is the measure of ease with which fluid can flow through its interconnected pore space. Production of hydrocarbon depends on Permeability of reservoir. Shale is generally not considered a source rock like limestone or sandstone based on differences in porosity and permeability, which impact ability to store and transmit fluids. While shale may contain organic material that can generate hydrocarbons through maturation processes, but due to intergranular attraction force it doesn't allow fluid to pass through it. Shale is more commonly associated with unconventional resources, such as shale gas and shale oil, where hydrocarbons are stored and extracted from the rock matrix itself rather than from traditional reservoir structures.

There are different methods to measure the permeability of a core, but the most common one is the steady-state method. In this method, you apply a constant pressure difference across the core and measure the flow rate of a fluid (usually air, water, or oil) through it.

1. Have a plan what you want to measure: Usually you want to know horizontal or vertical permeability of a specific rocktype at or around a particular depth. So you are looking for a homogenous interval, not a thinbedded intercalation of different lithologies. 2. Cut your plug in the desired direction, clean and dry it carefully. Measure only on good plugs that have sharp edges and no cuts/splits from drying. 3. Ideally you want to have all petrophysical parameters measured on the same plug, so you measure air-permeability first as other tests could damage the plug. 4. Keep the plug endpieces that you cut off, as you might want them for other (destructive) tests. Contact specialists for unconsolidated material and full-core measurements.

It is also important that the cleaning process does not change the internal structure of the rock, especially if some of its minerals are sensitive to high temperatures, water salinity, or chemical products (e.g., certain clays).

With the advancement of technologies, a day is not far when micro drones will be sent into the wells to collect the core samples to ensure accuracy in terms of formation(depth/lithology). Otherwise, the variation in depth(location of formation) and contamination in the real core samples(formation) is inevitable.

It's important to note that the choice of method depends on the specific characteristics of the rock and the objectives of the study. There are different methods to test the permeability of a rock core, and the choice of method depends on factors such as the type of rock, the purpose of the test, and available equipment. Here are some common methods: Variable & Constant Head Permeability Test Capillary Pressure Method Core Flooding Experiments Pressure Pulse Decay Test

There are some wireline logging tools like Modular Dynamic Tester (MDT) that measure mobility it means if viscosity is known , no need to have a core out of the well to measure permeability

Permeability (K) from Wireline Formation Tester (WFT) data may not be easily compared with core data, because: 1) WFT data provide the mobility value (K/μ), not the permeability. Given the uncertainty in the actual down-hole fluid and its μ, the calculated K carries a degree of uncertainty. 2) WFT measurement is usually done in the presence of more than one fluid, which means it relates to the effective K; while core data usually provide absolute K. 3) The quality of WFT data may be negatively affected due to lost seals or tight formations. 4) Flow geometry in WFT is somehow semi-spherical, which means it provides an average of Kx,Ky, and Kz; while core data provide K in one direction (linear flow).

It depends on what you want to measure. The problem is that reservoir rocks are not homogeneous and most of the time perm measurements are indirect ones. Let's say we take a sample from a core. Ideally, both should have the same perm, but actual measurements will be different. If before taking a core you performed a pressure test perm is just a volumetric-weighted value. If after the well is perforated you carry out a DFIT once again results will be different. Last but not least, tests in cores are generally done with gases alone so no multiphase effects. In the real world, you always will have at least two phases. So every time you decide to measure perm think twice about what you want to measure, and fully understand how to compare them!

Testing the permeability of a rock core is crucial in understanding its ability to transmit fluids. In addition to the testing steps outlined in item 3, I would include a final step called "repetition and validation of the measured permeability". By repeating the tests, checking for consistency, and validating results using multiple approaches including literature review, we can enhance the confidence in the measured permeability values and ensure that the data accurately represents the rock core's characteristics.

The rock specimen is then subjected to a given flow rate of water. By measuring the pressure differential across the specimen (upstream and downstream from the specimen) the pressure gradient is determined and the coefficient of permeability of the rock specimen is calculated. Permeability is not measured, it is calculated. Therefore, although it is a rock property and a constant for a given core sample, permeability values can vary according to the model and boundary conditions used in the calculation. To determine permeability, Darcy's law inherently assumes constant fluid properties.

Please Don’t mixed up single phase absolute permeability from multiphase effective/relative permeability. For absolute permeability, fluid viscosity has no effect (a parameter normalized in the Darcy equation) and wettability does not exist “oil tends to have lower permeability than water due to its higher viscosity and wettability.”

Measurement of absolute permeability at overburden condition for conventional and unconventional both types of reservoirs is crucial. Plug measured permeabilities usually klinkenburg or Swanson (micp) help in rocktyping/ flow unit modelling and resulted static or Geomodels provide realistic history match in simulation. Permeability measurement from T2 of CMR also good but requires calibration with plugs. And itself method is computationally expensive. There are many other empirical methods such as timur etc definitely for those methods porosity from either log must be calibrated to plug measurement. Core permeability should also be consider while defining the cutoff of the reservoir. Relative permeability shows hysteresis for ER.

Use historical production data from wells to refine permeability estimates. Matching simulation results with actual production data can help adjust and validate permeability models. Whenever possible, complement lab tests with in-situ measurements like well tests, which can provide direct insights into the permeability of the reservoir under actual conditions. Regularly update models and interpretations with new data as it becomes available, and validate them against field performance.

One important point is that permeability data from cores is the first entry point however next step is to include this data in the simulation model. Combination of permeability, porosity and pore pressure will confirm the model and will be the best tool for development and right placement of new wells.

Permeability is interpreted by assessing the ease with which fluids move through rock formations. High permeability indicates easy fluid flow, suggesting higher production rates. Conversely, low permeability implies restricted flow. Interpretation involves integrating permeability data into reservoir models to predict fluid behavior. Engineers use permeability to optimize well design, completion strategies, and enhanced oil recovery methods. It aids in economic evaluations of reservoirs and influences decisions in reservoir development. Accurate interpretation of permeability data enables informed decisions for efficient oil and gas extraction, ensuring the viability and productivity of subsurface reservoirs.

Uma das técnicas predominantes para otimizar a permeabilidade de um reservatório é o fraturamento hidráulico, que implica na injeção de um fluido composto por água, areia e aditivos a elevadas pressões. Esse procedimento induz a formação de fraturas na rocha. Subsequentemente, realiza-se a introdução de próppant para manter essas fraturas abertas. Ao liberar a pressão, as fraturas permanecem, facilitando o fluxo de hidrocarbonetos. Essa abordagem, particularmente eficaz em formações de xisto, requer vigilância constante para assegurar a segurança ambiental e operacional.

To complete the description: Hydraulic fracturing is a well-stimulation technique used to increase the flow of oil and gas from shale formations. In this process, a mixture of water, sand, and chemicals is injected into the rock formation at high pressure, which creates fractures in the rock. These fractures allow oil and gas to flow more freely to the wellbore. Acidizing involves the use of acids to dissolve the rock and create channels for oil to flow through. There are two types of acidizing: matrix and fracture. Matrix acidizing is used to increase permeability in the near-wellbore region, while fracture acidizing is used to create channels in the rock formation to increase the flow of oil and gas.

The way of oil extraction, making sure rocks let fluid flow smoothly is crucial. Techniques like hydraulic fracturing and chemical stimulation help open up paths for oil to move.

Una de las principales tareas de los ingenieros de yacimientos, es encontrar formas de desarrollar el yacimiento de manera eficiente y económica. Se trata de aumentar la producción de petróleo y el factor de recobro sobre la base de un plan de desarrollo científico y racional. Esto pasa por aplicar tecnologías en el proceso, en yacimientos de baja permeabilidad aplicar técnicas como Fracturamiento hidráulico o acido, y en el caso de yacimientos con buena permeabilidad, disminuir el daño de la vecindad del pozo, lo cual también implica un aumento de permeabilidad, pero en un radio más corto. En el caso de la reducción del daño nos referimos a estimulación, que puede ser matricial reactiva (acidos) o no reactiva (surfactantes, entre otros).

As long we know any technique that are 1 .Reservoir stimulation: Implement techniques like hydraulic fracturing or acidizing to create fractures or dissolve minerals in the reservoir rock, respectively. These methods can enhance permeability by increasing the connectivity between the reservoir and the wellbore. 2. Enhanced oil recovery (EOR) methods: EOR techniques, such as water flooding, gas injection (CO2 or natural gas), or chemical flooding, can be employed to improve oil displacement and increase permeability. These methods help reduce the viscosity of the oil or displace it more effectively within the reservoir. But many consideration for improve permeability rock

Testing permeability is essential to know the deliverability of an Oil and Gas well. This would define how much rates can be produced. Another important term associated with this is called Mobility, which is permeability divided by viscosity that is also a good indicator of flow capability of reservoir. Usually expressed as md/cp. It is worth mentioning here that overall cost of getting mobility data is usually lower than getting a core and then measuring permeability of core sample.

El método convencional de estimaciones de permeabilidad K es a través de correlaciones porosidad-permeabilidad. En mi preparación de este semestre para mis estudiantes de Ingeniería de Yacimientos encontré una estimación confiable, especialmente en formaciones geológicas con una rápida variación de los componentes rocosos, observando la distribución espacial. El flujo de trabajo propuesto fue 1) definir las unidades hidráulicas, 2) Con RMN los cambios en la distribución del tamaño de los poros, 3) calcular con imágenes de tomografía computarizada 2D y fotos de núcleos con datos de RMN y 4) El uso de modelos de física de rocas basados en clases. Se redujo el error relativo medio hasta en un 37% (fuente: SPE-209979-PA).

Permeability is a tensor. Core measurements can in no way measure the actual permeability but only the pressure loss in an arbitrarily defined one directional flow; in addition the scale at which core permeability can be measured is way lower than the scale at which reservoir flows take place Core permeability is thus only a sometimes very vague (but still useful) indication. It has to be complemented with data from WFT and well test, which have their own limitations and boundaries, and investigate different scales. Consequently the actual permeability field cannot be exactly defined but can hopefully be sufficiently approximated integrating these data and analyzing the way they can be up/down scaled. It is however not always possible.

It is worth mentioning that permeability can be affected by tectonic factors. In Siliciclastic rocks close to the core of geological fault deformation this property has its values reduced by a few orders of magnitude and increases as you move away from this core towards the undeformed rock. This permeability variation can be a key factor in modeling and numerical simulation of reservoirs in the production direction (reservoir to well), to increase the recovery factor, or in the injection direction (well to reservoir), so that the fluid injected cover the desired area.

Advanced methods include nanotechnology, where nanoparticles are injected into the rock to alter pore structure and increase permeability. Additionally, 3D printing can create customized rock models with desired pore geometries for testing and optimization. Biologically induced mineralization utilizes microorganisms to precipitate minerals within the rock, opening pore spaces. Furthermore, laser-induced thermal fracturing applies focused laser energy to create microfractures, improving permeability.