Formation Damage caused during drilling can have a significant impact on the near wellbore and the ability for a well to deliver to design. The reduction in near wellbore permeability is generally interpreted as a negative and the damage is normally minimised through careful selection of fluids, drilling methods and parameters. The focus on formation damage usually comes during development well planning, where optimum productivity or injectivity are required. Formation damage can also have an impact on core quality when cores are being cut and recovered to surface. Good quality core is valued by Formation Evaluation and indeed, formation damage specialists, as it enables direct measurement of rock and fluid properties on real samples of real reservoir. It is well known that core retrieved too quickly from reservoir to surface can be physically damaged by “gas expansion”. Previous work has demonstrated that gas expansion damage should only be a major issue in low permeability reservoirs ( Zubizarreta, 2013 ; Hettema, 2002 ). However, higher permeability reservoir cores can also be damaged ( Worthington, 1987 ; Holt, 1994 ). Consider the core surface and a few milimeters in to the core – mud cake and damage occur. The permeability of damaged zone is significantly lower than reservoir rock. In gas reservoirs or when bubble point is reached in high GOR, core retrieval leads to pressure difference across the damaged zone and desaturation of the mud cake damaged zone. If this pressure difference exceeds strength of rock then a thin layer of damaged rock material may develop. This fracturing of the core can render it useless for many of the normal laboratory tests conducted on core. This paper will present evidence of structural damage developed due to formation damage around reservoir core. We will also present the modeling method used to predict this damage and give some examples of core tripping out schedules designed to protect the valuable core resource. The impact of formation damage on core structural integrity will be explored in detail for the first time and the method presented can be used to predict and avoid structural damage in future coring operations.

Over the years, sandstone acidizing has experienced low success rate. This makes it essential to develop a systematic method for selecting the optimum hydrofluoric acid (HF) concentration, which can achieve the highest possible permeability enhancement. Field experience and experimental studies show the significance of HF acid concentration in controlling the outcome of the treatment: adding too much HF acid will result in secondary and tertiary reactions damaging the reservoir while the use of low concentrations of HF will result in insufficient dissolution. The objective of this study is to investigate the effect of HF acid concentration and design a systematic method for designing sandstone-acidizing treatments. Experimental work was designed to investigate the effect of the HF acid concentration, and identify the optimum concentration for different sandstone formations. Two types of sandstone cores were used in this study: Grey Berea which is characterized by low carbonate content (3 wt%), and Bandera which has a high carbonate content (16 wt%) and high content of troublesome minerals (10 wt% illite). Coreflood experiments were performed on 6 in. cores with 1.5 in. diameter. Temperatures of 280 and 325°F were used for the experiments to address the moderate and high temperature applications. HF acid concentrations varied from 0 to 3 wt% HF. Optimum concentrations were selected based on the ratio of permeability improvement. Inductively coupled plasma (ICP) was used to measure the concentrations of key ions in core effluent. The experimental results proved the relationship between the acid concentration and mineral content. At the temperature of 280°F, Grey Berea cores, with clay content of 8 wt% and 3 wt% feldspars, the HF concentration of 1.5 wt% was able to achieve the best results. For the Bandera cores, which have a clay content of 14 wt% (10 wt% illite, 1 wt% chlorite, 2 wt% kaolinite) and 12 wt% feldspars, the acid that achieved the best results contained 1 wt% HF. When temperatures were increased to 325°F, permeability enhancement was significantly decreased while the optimum concentration remained fairly at the same HF concentration. This proves that the optimum acid concentration is independent on the temperature, but for high temperatures (>300°F) retarded acids should be considered. This work introduces the concept of designing acid treatments as a function of the mineral content. The optimum concentration of the HF was proven to adopt an inverse relationship with the mineral concentration. The proposed relationship can be used to determine the optimum acid concentration required for sandstone stimulation.

Gyda is a mature oil development in the Norwegian sector of the North Sea. The first production wells were drilled more than twenty years ago. This study focuses on wells drilled in the porer reservoir quality areas of the Gyda reservoir. Some recent production wells have significantly underperformed relative to equivalent initial wells. In particular, a sidetrack to an early successful well, had very poor performance on initial start-up. The geometry of the original well and the sidetrack were simulated, together with various assumptions and sensitivities to formation damage. In the original well an attempted hydraulic fracture had been assumed to have failed. This assumption was challenged in the model. The model demonstrated that the original well must have included a successful hydraulic fracture in order to flow at the historical rates recorded. In addition for the sidetrack, that contained no fracture, there were indications that the perforation tunnels may not have fully cleaned up and that whilst the well performance may recover somewhat with time, a significant change in completion would be required in order to match the performance of the original well. The model constructed included the completion geometry and formation damage and has enabled evaluation of old wells and more importantly, design of new wells in this mature reservoir development.

Many studies have been performed to identify chemical additives that will aid shale stability in large volume slick water fracturing treatments. Most of the targeted shale formations have a very low permeability, do not experience conventional leakoff and do not contain high amounts of swelling clays such as smectite, leading to a perception that the shale is not water sensitive. However, recent laboratory evaluations have shown that not all shales are stable in fresh water, destabilizing with fresh water contact and releasing fines which could potentially result in formation damage and reduce net fracture pack conductivity. Previous studies of the ability of inorganic salts, temporary clay stabilizers, and permanent polymeric based clay stabilizers show that some of the common hydraulically fractured shales encounter stability problems when contacting fresh water. The studies have revealed that cationic polymeric permanent clay stabilizers improve the stability of the water sensitive shales. However, polymeric shale stabilizers are not without potential detriments. Polymers can lead to formation damage by blocking pore throats and reducing permeability. Additionally, the use of cationic polymers can limit the use of other chemical compounds used in treating fluids that may not be compatible with the cationic charge. This paper will compare a non-polymeric permanent clay stabilizer to conventional cationic polymers, temporary clay stabilizers, and inorganic salts and demonstrate equivalent and, sometimes, improved performance. Laboratory data from shale stability (roller oven), capillary suction time (CST), and regained permeability (core flow) studies will be presented demonstrating the efficacy of this new compound. Shales selected for the study will include standard Pierre shale and a variety of commonly hydraulically fractured shales from North America. Additionally, chemical compatibility testing will demonstrate the benefits of the new compound over conventional cationic polymeric clay stabilizers.

Many gas wells in unconsolidated sandstone reservoirs have been completed with stand-alone screens (SAS) that use either wire-wrapped screens (WWS) or mesh screens. This method is a cost-effective sand-control method for completions, especially in horizontal (Hz) wells where gravel packing (GP) may not be attractive for economic, operational, or logistical reasons. Because there are annular-flow failure concerns with this type of completion, a simple well-modeling study was conducted to look at the potential for application of inflow control devices (ICDs) to minimize annular velocity in Hz gas wells. This paper will discuss the annular flow results. The purpose of the study was to investigate methods that could mitigate ‘hot spotting,’ a type of screen failure that can occur in an SAS completion, especially in high-rate gas wells. This type of failure occurs when fluid flow carrying abrasive particles is concentrated over a small area such that the entrance velocity is above the threshold for erosion. Swellable packers have been used to compartmentalize the SAS completion into many segments in an attempt to control annular movement of abrasive particles by minimizing annular velocity. However, the well modeling study discussed in this paper has shown that compartmentalization alone may not be sufficient. This paper discusses the nodal-analysis software modeling tool that was used to build the well hydraulic models and to investigate the following flow behaviors: Annular velocity Effect of compartmentalization on annular velocity Annular velocity in SAS-ICD completion Effect of compartmentalization on annular velocity in SAS-ICD completion Effect of ICD resistance on annular velocity The study will show that 1) an SAS-ICD completion can be effective in minimizing annular flow, and 2), it appears to be the most effective means of minimizing annular flow in gas wells, ultimately reducing the chance of failure.

Abstract One of the great challenges facing our industry is accurate prediction of well inflow. Conventional methods have been too cumbersome and imprecise and have suffered from a lack of accuracy and clarity. Informed use of computational fluid dynamics, fine scale modelling and improved computing power enable far more accurate prediction of the impact of formation damage and thus of well performance. The accurate prediction of well performance helps with appraisal of development prospects, well planning and reliable prediction of true well and field value. If we know what the outcome of our actions and of our well designs will be, then we can make sensible and informed choices on damage impact and mitigation. Results from laboratory simulations of drilling and completion operations were generated from "standard" return permeability testing. The detailed data obtained, and its millimetre scale resolution was incorporated in to a well specific model. The damaged and undamaged states were examined using flow rate predictive computational fluid dynamics. The impact on flow in a single and dual permeability reservoir interval were calculated. In a specific example presented, the case for underbalance drilling was clearly made as the impact of overbalance drilling was predicted to have a severe impact on well productivity. The results of accurate and detailed laboratory simulation of formation damage have been translated using innovative software applications to give a prediction of well performance. This is the first time that computational fluid dynamics has been employed to predict well performance based on high quality laboratory testing. In future the laboratory tests will be designed to yield data most useful for the model and the model and grid scale will continue to be adjusted based on the specific challenge and objective. The detailed workflow used to achieve more accurate well performance prediction will be outlined in the paper. Introduction Modeling of permeability, pressure drops and formation damage in the near wellbore is an art that has suffered from lack of input and lack of tools in the past. The input deficit has largely been driven by poor or incomplete measurement and knowledge of formation damage mechanisms. These are not very often identified or quantified and some of the basic assumptions and rules of thumb for damage are simply incorrect. Even when properly understood and measured, existing industry software, inflow performance relationship models are inadequate tools to capture the detail and complexity of damage distribution. They generally accept only a very simple input of damage magnitude and thickness. Often data is altered in order to match the model. This is entirely the wrong way around. In building the workflows to model and understand damage, our guiding principal was that the model must alter to capture the damage rather than the other way around. Previous authors have attempted to model damage and create near wellbore inflow models which incorporate flow restrictions to a fine scale (Bennion et al 1996, Burton et al 1997, Han et al 2005, Yildiz 2004, Qutob and Ferreira 2005). These could be termed very near wellbore models of damage, most of which are numerical 2D models. Our objective here is to create a process through which complex very near and very, very near well inflow models can be created in 2D, 3D and 4D. The overriding objective is accurate prediction of well productivity and injectivity which will enable thorough well and completion designs and enable focus on real production barriers rather than speculation and heresay.

Abstract The problem of formation damage, i.e., permeability reduction due to injection of particulates, is a matter of interest in several engineering fields. In the previous attempts to model the external cake formation, cake thickness has been considered to be only dependent on time; even though, in practical applications the dependency of the cake profile on space can be important. In this paper a novel model has been developed to describe the steady state external filter cake thickness profile along the well-bore. A set of equations are derived from the force balance for a deposited particle on the cake surface and the volume conservation of the fluid in the well-bore. These equations are combined with the Darcy's law in radial geometry and the equation of flow in the well-bore, and solved numerically to obtain the cake thickness and fluid velocity profiles along the well-bore. 1. Introduction Many oil and gas reservoirs are connected to water source connected to their hydrocarbon reserves. Therefore, the produced fluids are not exclusively hydrocarbons but contain water, often in very large amounts of water Worldwide 75% of the production is water [1] and in some regions this fraction may reach to 98% [2]. Produced water (PW), depending on the geological formation and lifetime of the reservoir, contains organic and inorganic materials including solid particles and oil droplets. Disposal of the PW is a challenge for petroleum industry due to the high costs of the transportation and filtration facilities and the increasingly stricter environmental regulation. One economically and environmentally friendly method is to re-inject the produced water into the formation. By re-injecting the produced water reservoir pressure can be maintained simultaneously. Nevertheless a rapid injectivity decline is usually observed in the PW injection processes due to the presence of impurities, usually solid particles and oil droplets. The injectivity decline is caused by the deposition of the particles inside porous media (internal filtration) [3] or accumulation of the particles on the surface (external filtration) [4]. In the latter case, particles form a cake (porous medium), which is orders of magnitude less permeable than the reservoir. Filtration of the particles in the borehole can occur under either static (dead-end) or dynamic (crossflow) flow conditions. Crossflow filtration refers to a pressure driven separation process in which the permeate flow is perpendicular to the feed flow. In the crossflow filtration, the thickness of the fiklter-cake is limited by the shear forces due to the flow of the produced water containg particles parallel to the borehole surface. A similar phenomenon happens when drilling mud flows across the borehole surface [5]. The drag force caused by the flux of permeate pushes the suspended particles towards the cake. Many authors have investigated the problem of crossflow filtration [6–17]. It has been suggested in the literature that temperature, pressure, shear rate (i.e., flow rate) and the permeability of the formation influences the filtration process. However, the effect of individual parameters has remained unclear [5]. In petroleum engineering transport of fluid containing particles in the subsurface is similar to crossflow filtration. For example, in the fractures, the transport of the particles in the injected fluid results in formation of the cake on the rock surface. Al-Abduwani et al. [18] developed a model to obtain the filter cake profiles in an experimental set-up. Their model can be applied for the formation of cake in the fractures (linear cases). Another example is the build-up of mud cake during the water injection or drilling of the well around the borehole. In this paper we adapt the model described in ref. [18] to obtain the filter cake and velocity profiles in a radial geometry.

Abstract All rocks are sensitive to changes in stress. In the Dulang Field sandstones, stress sensitivity is affected by differences in texture, mineralogy and clay type. In this study, we present the results of a study that shows how stress sensitivity is related to the make up of a rock and how itaffects the productivity. The sensitivity of permeability - and therefore transmissivity - to stress in the Dulang Field strongly correlates with the general classification of reservoir quality with better quality rocks showing lesser sensitivity to stress. However, there are some anomalies in the stress sensitivity of porosity. While the sensitivity of permeability to stress increases with decreasing rock quality, the same does not hold for the sensitivity of porosity to stress. These deviations are explained by changes in cementation, clay type, clay morphology and clay locations in the pore structure. Understanding why stress sensitivity changes in the Dulang Field is essential for its future development. Knowing the reasons behind reservoir behaviour allows better prediction and control of future production. Some zones will compact differently from others as the field produces. Differences in compaction are due to the different make up of the reservoir rocks. Heterogeneity in compaction affects the productivity irregularly, and therefore, the economics of the field. By knowing which zones are likely to compact first, production rates and scheduling can be adjusted to reduce the stress-induced damage. The findings of this study can be used to make more realistic prediction of future production rates via numerical simulators, thus providing a tool for improving field management and company profits. This is important not only for the Dulang Field, but also for any field where changes in stress are likely to affect production due to heterogeneous compaction of the reservoir. Introduction Reservoir compaction during fluid withdrawal is simply a response to change in in situ stress conditions. Owing to the production of fluids from a reservoir, pore pressure declines while overburden stresses remain constant. The relative increase in stress caused by production alters all physical properties of rocks. The degree of alteration in rock properties is heterogeneous owing to the heterogeneous make up of the rocks. The varying degree in compaction manifests itself as different percentages of reductions in porosity and, most importantly, lessening of transmissivity. The direct effect of reduction in transmissivity is a drastic decline in fluid flow through the rock. This study generates a stress-sensitivity profile that shows vertical variation in the proneness of the reservoir to compaction. This provides a tool for adjusting and scheduling production rates to prevent stress-induced damage.