Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.

There are many possible causes of formation damage. In addition to the numerous sources identified in separate articles (see See Also section below), other, less common causes include emulsions and sludges, wettability alteration, bacterial plugging, gas breakout, and water blocks. The presence of emulsions at the surface does not imply the formation of emulsions in the near-wellbore region. Most often, surface emulsions are a result of mixing and shearing that occur in chokes and valves in the flow stream after the fluids have entered the well. It is uncommon to have emulsions and sludges form in the near-wellbore region without the introduction of external chemicals.[1]The

Swelling clays, although relatively abundant in shales, do not occur as commonly in producing intervals. Thus, formation damage problems with swelling clays are not nearly as common as those associated with fines migration. The most common swelling clays found in reservoir rock are smectites and mixed-layer illites. It was earlier thought that much of the water and rate sensitivity observed in sandstone permeability was caused by swelling clays. However, it is now well accepted that the water-sensitive and rate-sensitive behavior in sandstones is more commonly the result of fines migration and only rarely of swelling clays.

A high-carbon-dioxide (CO2) carbonate gas field offshore Sarawak, Malaysia, is scheduled for development. Reservoirs in this region have an average clay content of 8%; more than 50% of this clay content is migratory illite, and 15% is migratory kaolinite. Therefore, fines migration exacerbated by this low-permeability rock becomes a potential production and injection problem. A study was conducted involving rock mineralogy and dynamic flow to evaluate factors contributing to potential fines-migration damage within the production and injection interval. Migration of fines is associated with oil and gas production in sandstones as well as carbonate reservoirs.

In recent years, many studies have focused on investigating formation damage caused by produced-water reinjection (PWRI). Nevertheless, many questions about this subject remain unanswered, particularly with respect to the occurrence of this phenomenon in unconsolidated sands. This paper describes a coreflooding program performed with sandpacks at different permeabilities, water qualities, and injection conditions. The authors performed a complete experimental laboratory study using suspensions containing solid particles, mono-sized oil droplets, or both. Several coreflooding experiments using highly permeable sandpacks were performed over a long duration, during which significant volumes, sometimes reaching 100 L, have been injected.

Summary During well completion operations, the wells are killed with specific fluids to control the well. These fluids can invade and damage the formation because of fluid/rock interactions. Fluids such as fresh water, brines, and weighted fluids (e.g., barite weighted, calcite weighted, and bentonite weighted) are used to control the formations during completion operations. These fluids can invade and interact with clays and damage the formation. In addition, these fluids may alter the near‐wellbore wettability and make them more oil‐wet, thereby affecting the production from these formations. In this work, polyoxyethylene quaternary ammonium gemini surfactants with different types of spacers are proposed as clay swelling additives in completion fluids to mitigate the formation damage in unconventional reservoirs. Adding the new surfactants will maintain the in‐situ permeability and avoid the formation damage. The novel gemini surfactants are tested on unconventional tight sandstone formation enriched with high clay content to mitigate the formation damage during well completion. The process involved a complete stabilization of clays using gemini surfactants added in deionized water (DW). Coreflooding experiments were carried out on Scioto sandstone rock samples with an average porosity of 15.6% and average absolute permeability of 0.25 md. Several coreflooding experiments were carried out with different fluids, such as potassium chloride (KCl), sodium chloride (NaCl), and different classes of gemini surfactants. Coreflooding experiments were designed in a way that the cores were preflushed with the subjected fluid and then post‐flooded with DW. Results showed that the cores saturated with KCl and NaCl solutions lost permeability significantly when flooded with water while gemini surfactant solutions maintained the same permeability even after being treated with DW. Conditioning with the KCl solution resulted in a 38% reduction of permeability and that with NaCl solution resulted in an 80% reduction of permeability when treated with DW. No significant change of permeability was found for the case of gemini surfactants. This indicates that the synthesized surfactants can be used for well completion operation without any side effects.

Summary Conformance control treatment in high-temperature and ultrahigh-salinity reservoirs for easing water/gas channeling through high-permeability zones has been a great challenge. In this work, we propose a deformable microgel that can be used at more than 373.15 K and ultrahigh-salinity conditions (total dissolved solids  > 200 kg/m, Ca + Mg > 10 kg/m) and present a method for choosing the suitable particle size of the microgel to achieve an optimal match with the pore throat of the core. First, the particle size distribution of the microgel was analyzed to decide d50, d10, and d90 (diameter when cumulative frequency is 50, 10, and 90%, respectively). Coreflooding experiments were conducted under different permeability conditions from 20 to 900 md to investigate the migration and plugging patterns of the microgel by analyzing and fitting injection pressure curves together with the change in the morphology of the produced microgel analyzed by a microscope. The migration and plugging patterns were divided into three patterns: complete plugging; plugging—passing through in a deformation or broken state—deep migration; and inefficient plugging—smoothly passing through—stable flow. The second pattern can be further divided into three subpatterns as strong plugging, general plugging, and weak plugging. Finally, on the basis of five patterns, we build a quantitative matching relation between the particle size distribution of microgel and the pore-throat size of cores by defining three matching coefficients α = d10/d, β = d50/d, γ = d90/d (d is the average pore-throat diameter). The effectiveness of this quantitative matching relation was verified by evaluating the plugging ability (residual resistance factor) in a post-waterflooding process after the injection of 1.5 pore volume (PV) of microgel. For a strong permeability heterogeneity, the strong plugging is believed to be the expected pattern. The particles size and the pore-throat size should meet the following relationship: 1 < α < 2, 2 < β < 4, 4 < γ < 6. In this scenario, the deformable microgel particles could achieve both an effective plugging and a deep migration. The quantitative matching relation with multiple matching coefficients determined based on the particle size distribution might help to choose suitable particles more precisely in comparison to the method based on one matching coefficient (mostly, the ratio of the average diameter of particles to the average pore-throat diameter). In addition, the method itself to build a quantitative matching relation according to particle size distribution can be used for designing different particle-type conformance control agents for profile control and water shutoff treatment in field applications.

Abstract Much work has been done on hydraulic-fracturing as a well stimulation technique but our understanding of formation damage due to fracturing is limited. This is due to inherent complexity of shale-water interactions under subsurface conditions. Damage is triggered by cold and low-salinity water invasion into the formation. Here, we introduce the formation damage mechanisms as a multi-physics/chemistry problem developing in a region near the fracture-matrix interface. Using high-resolution flow simulation models, we investigate the mechanisms and their impact on natural gas production. The simulation model includes geo-mechanically fully coupled non-isothermal multi-component two-phase flow equations that are developed for a multi-scale porous medium representative of the shale formations. We consider the occurrence of formation damage during two consecutive periods: well shut-in period which is considered to begin with the completion of fracturing and extending 1-2 days; followed by water flow-back and gas production period which takes months. During the early shut-in period, cold water invasion leads to thermal contraction of the matrix and reduces the normal mean stress. These changes improve the formation permeability temporarily, they may create secondary fractures, and modify the capillary pressure and saturations in the water invaded zone. These thermal effects are reduced rapidly, however, due to heat supplied by the reservoir. Osmosis pressure and the associated clay swelling cause the formation matrix to absorb fracturing water, reduce the matrix permeability, and amplify the capillary pressure/saturations. In summary, the well goes to the flowback and production with modified near-fracture conditions. During the water flowback the water saturation near the fracture-matrix interface increases; hence, liquid blockage effect on the gas flow becomes larger than that predicted based on the water imbibition during the shut-in only. This is due to capillary-end-effect developing near the interface during the water flow-back, when the fracturing water is displaced by the gas, i.e., drainage. Clay swelling and stress change continue during the withdrawal of the fluids. Consequently, we observe significant impairment in gas production rates. Only a fraction (<20%) of the injected water is ultimately produced back from the shale gas wells; the rest stays in the fractures and invades into the formation. Our simulation work shows that it is mainly the water in the fractures that are produced. The rest stays in the fractures due to relative permeability effects therein, and in the matrix as capillary-bound water due capillary end effect and to clay-swelling.

Abstract Near-wellbore clay fines migration presents a formation damage risk in many gas wells. Fines mobilization can occur due to weakened electrostatic forces on ion exchange with an introduced fluid making them more prone to movement by viscous drag, or where the drag forces are sufficient to physically break or lift clay crystals from their original location, and distribute them throughout the pore network. Fines migration potential is typically assessed via coreflood tests on reservoir core material. Ideally, fines migration tests should be carried out on reservoir core with reservoir gas, at reservoir rate and pressure conditions, but it is often more practical (and less expensive) to scale higher field pressures down to lab scale. However, in order to reproduce the total gas flux observed in a given near-wellbore system, flow rates are routinely increased to counter the pressure decrease. This paper aims to address whether this current lab practice is valid, and to identify alternative yet practical test protocols and fluids that might more closely represent the reservoir gas properties (density and viscosity) that control the drag forces. Reservoir core is often scarce or unavailable, which means that it can be difficult to evaluate different core flood test protocols and fluids. Outcrop samples provide a convenient alternative as they are readily available and cheap to acquire. This paper describes the first phase of a research program that aims to identify outcrop sandstones that are prone to fines migration as a result of drag forces on gas flow, and to evaluate different test protocols. Coreflood tests were carried out on clay rich (predominantly kaolinite) Blaxter sandstone, with samples having a typical permeability of approximately 30-40mD. Potential permeability impairment from fines migration was assessed by sequential and incremental critical velocity tests at both low (290 psig) and high (1450 psig) pressure conditions, and at gas rates of up to 2 L/min. Tests were performed with nitrogen (OFN), and gaseous and supercritical carbon dioxide. In addition, hydrocarbon gas analogues (hexane and dodecane) were also evaluated as a substitute for dense gases in coreflood testing. Initial critical rate tests using KCl brine showed the potential for salinity-related permeability damage in Blaxter sandstone cores, demonstrating that these cores are susceptible to fines migration. However, test results using anhydrous gas demonstrated that pressure and flow rate variation in the laboratory had no notable fines migration effect on the Blaxter sandstone samples. In addition, the use of different hydrocarbon gas analogues showed that even when the test fluid density is selected to so that it is similar to a liquid - supercritical CO2, or light hydrocarbons such as hexane and dodecane - fines migration is still absent even at high flow rates. The outcrop core test results do not necessarily indicate the absence of fines migration potential in gas wells. The kaolinite fines in Blaxter sandstone may not display the well-developed clay crystal structures and morphologies normally associated with reservoir sands, and which may expose the clays to higher drag forces. The case studies presented here will aid in improving coreflood test protocols for assessing formation damage in gas wells. This improved understanding will ultimately enhance the application of core flooding as a tool for identifying formation damage in gas wells.

Abstract This work examines the potential use of two different nanoparticle solutions for EOR applications. Combining the evaluation of fluid-fluid interactions and spontaneous imbibition experiments, we present a systematic workflow. The goal of the study was to enable the generation of predictive scenarios regarding the application of Nano-EOR in OMV's assets. Therefore, influence of high and low TAN crude oil, core mineralogy, composition of the nanofluid on wettability alteration and recovery were studied. Nanomaterials used in this work employ inorganic nano-sized particles in a colloidal particle dispersion. We evaluated two types; one utilizes surface-modified silicon dioxide nanoparticles, while the other employs a synergistic blend of solvent, surfactants and surface-modified silicon-dioxide nanoparticles. IFT experiments were performed using a spinning-drop tensiometer and results were compared at ~180 min of observation. Amott-Harvey experiments enabled investigating wettability alteration considering effects of crude-oil composition and core mineralogy (~5 and ~10% clay content). Interfacial tension reduction was observed for both nanofluids. The blend yielded slightly lower values (~0.5- 0.6 mN/m) compared to the nanoparticles-only fluid (~0.8 mN/m), which is most likely related to the surfactant contained in the formulation. Amott-Harvey spontaneous imbibition experiments depicted clear wettability alterations for both nanofluids. Cores with ~5% clay content exhibited a water-wettish behavior, and additional recoveries using the nanofluids were up to 10%. In the cores containing ~10% clay, the nanoparticle-only fluid spontaneously imbibes to the rock matrix and quickly displaces large amounts of oil (~70% independently of the oil type that was used). Contrary, the blend yields higher recovery from the 10% clay cores, with the high TAN oil than with low TAN oil (57 ± 3 vs. 45 ± 1%). However, in 5% clay cores, faster imbibition was observed when the blend was used, which can be explained by a higher capillary pressure. A special case was observed in cores with 10% clay content (Keuper), where the baseline experiments using brine exhibited a high standard deviation. We attribute this behavior to the large mineralogical heterogeneity of the Keuper cores and the heterogeneous distribution of clays and mineralogical impurities. Both the blend and the surface-modified nanoparticles managed to restore a water-wet state, and additional promising recoveries were up to 65% in the case of strong oil-wetness. Nano-EOR is an embryonic technology; hence, literature data is scarce on how oil composition and reservoir mineralogy could influence its use to obtain additional recovery and maximize benefits. Our systematic workflow, helps understanding the parameters that require detailed evaluation in order to forecast recoveries for field tests. The experimental synergies provide a good approach to evaluate fluid-fluid and rock-fluid interaction.