The influence of individual clay minerals on formation damage of reservoir sandstones is reviewed, mainly through the mechanism of fine particle dispersion and migration leading to the accumulation and blockage of pore throats and significant reduction of permeability. The minerals discussed belong to the smectite, kaolinite, illite and chlorite groups respectively. These minerals usually occur in an aggregate form in reservoir sandstones and the physicochemical properties of these aggregates are reviewed in order to reach a better understanding of the factors that lead to their dispersion in aqueous pore fluids. Particularly significant properties include the surface charge on both basal and edge faces of the clay minerals and how this varies with pH, external surface area of both swelling and non-swelling clays, porosity and pore size distribution in the micro- and meso-pore size range and overall aggregate morphology. For non-swelling clays, and perhaps even for swelling clays, dispersion is thought to be initiated at the micro- or meso-pore level, where the interaction between the pore solution and the charged clay surfaces exposed on adjacent sides of slit- or wedge-shaped pores brings about expansion of the diffuse double electric layer (DDL) and an increase in hydration pressure. Such expansion occurs only in dilute electrolyte solutions in contrast to the effect of concentrated solutions which would shrink the thickness of the DDL and so inhibit dispersion. Stable dispersions are formed, particularly where the solution pH exceeds the isoelectric pH of the mineral, which is often at alkali pH values, so that both basal face and edge surfaces are negatively charged and the particles repel each other. The osmotic swelling of smectitic clays to a gel-like form, so effectively blocking pores in situ, is often invoked as an explanation of formation damage in reservoir sandstones. Such swelling certainly occurs in dilute aqueous solutions under earth surface conditions but it is uncertain that stable smectitic gels could form at the temperatures and pressures associated with deeply buried reservoir sandstones.

Formation damage testing is commonly used to gather information and aid in risk-reduction when making operational decisions. The nature of laboratory testing means that it is a higher risk to rely on permeability and pressure measurements alone, so various techniques (including scanning electron microscopy and thin section) are used to gather additional information and aid interpretation. The current techniques provide excellent high-resolution data but are limited in terms of capturing the change throughout an entire core sample.The paper presents a new approach which utilises micro-CT scanning to produce high-resolution data of entire core samples. The images of core produced are superior to those from the commonly-used medical scanners, and give insight into core properties as well as areas such as drilling mud constituents infiltration, mud-cake structure and thickness, and alterations in the pore network. Through a technique that we have called "difference mapping", data sets captured before and after laboratory testing are compared to reveal the distribution of changes within samples. Difference maps can be used to provide additional interpretation of tests results as well as combining with current techniques to target their sampling locations. The combination of laboratory data with tools that allow visualisation of both the distribution and nature of damaging mechanisms makes laboratory data more valuable and therefore decreases risk in operational decision-making.The technique is illustrated by a case study from Centrica's South Morecambe gas field. Here a series of experiments were carried out to aid in the selection of drilling mud for a cased & perforated well. Whilst permeability was relevant, it was most important to have a fluid that did not contribute deep damaging mechanisms or produce high fluid losses. Laboratory test data showed very significant reductions in permeability, which would normally be a concern if there was not an understanding of the nature of damage. Micro-CT scanning, in combination with geological analysis, showed that the damaging mechanisms were concentrated within the drilling mud-cake, attachment of the drilling mud-cake to the core sample, and drilling mud constituents within the first few pores of the core sample. Only scattered change, caused by some drilling mud filtrate retention and clay fines mobilisation, was seen deeper in the majority of samples; in a cased & perforated scenario the vast majority of damage would therefore be expected to be bypassed. This illustrated the value of the combination of micro-CT scanning and geological techniques to allow greater insight and more meaningful conclusions.

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Monovalent formate brines were first introduced into the oilfield environment in the early-1990's, in response to the industry demand for better drilling and completion fluids to meet the increasingly complex technical challenges posed by modern well construction practices. After years of rigorous field-testing, in a variety of demanding well construction operations, the formate brines are now acknowledged to be probably the best foundation for any modern high performance drilling and completion fluid. The formate brines are currently having their greatest impact as the primary components of HT/HP reservoir drilling and completion fluid formulations. A number of field and laboratory tests have indicated that when formate-based formulations are used as reservoir drilling-in and completion fluids they appear to cause less formation damage than some other conventional fluid formulations, and consequently they are often seen to have a beneficial effect on well productivity. Up until now, however, little of this important information has found its way into the public domain. It has been common practice for a number of the major multinational oil companies to contract a specialist formation damage prediction company to carry out laboratory-scale formation damage tests with formate brines before using these fluids in their well constructions operations. This paper draws together the results of a significant number of these tests carried out by the specialist laboratory using formate-based fluids passed through real reservoir core materials for realistic time periods and under realistic reservoir conditions. As well as providing a unique insight into the interaction between formate brines and a range of reservoir core materials and reservoir fluid types under simulated downhole conditions, this paper also outlines the methodology developed to ensure that the formation damage tests carried out with formate brines are not influenced by laboratory artefacts. The conclusion of the paper is that a significant number of laboratory results, obtained under test conditions closely simulating reservoir conditions, tend to lend support to the growing perception that formate brines have valuable formation damage control properties that can be exploited to improve well productivity prospects in even the most demanding environments. Introduction Brines are used by the oil industry in a range of well construction operations, most commonly to create dense low-solids fluids for application in reservoir sections. A key driver for using brines in these applications has been the need to maintain well control while trying to minimise reservoir formation damage from solids invasion. Traditionally these oilfield brines have been based on halide (chloride or bromide) salts. Unfortunately the halide-based brines were never purpose-designed for oilfield applications and they have a number of performance deficiencies that become amplified as the brine density requirement is raised. Nevertheless, in the unsophisticated well construction environments that have existed in many parts of the world until relatively recently it has been possible for operators to somehow live with these deficiencies, albeit at some present or future financial cost. In recent years it has been clear that the traditional halide-based brines could no longer hope to meet the technical challenges of the increasingly complex and extreme well constructions that were being attempted to reduce field development costs and to increase production. In addition to the technical challenges that the traditional halide brines have been facing they have also been coming under pressure from the Health, Safety and Environmental lobbies. The use of halide-based brines in onshore environments has always been a concern anyway, given the toxicity of halides to aquatic life and all other non-marine organisms, and it can be expected that the legislation controlling the onshore application of halide brines will become more and more stringent.

Reservoir conditions core flood tests have been carried out to examine the damage arising from overbalanced drilling-in operations. Gannet field cores were exposed to a number of water- and oil-based field muds currently in use by Shell Expro. Results showed that the initial permeabilities to crude oil were dramatically reduced after exposure to overbalanced mud and subsequent back production of crude oil. Thin section petrography and SEM/XRD analysis of the cores clearly showed the source of impairment in all cases to be a thin layer of mud solids plugging pores and throats exposed to the wellbore face, forming an effective permeability barrier that was not dislodged by crude drawdown under realistic drawdown. The results were confirmed by trimming of 1 cm from the wellbore face of the core that led to a restoration of initial permeability. Introduction The issue of formation damage has returned to prominence with the exponential growth of horizontal wells in recent years. The increase in productivity offered by the increased contact between reservoir and wellbore is a two-edged sword. The increased contact also allows an increased area of damage to form. The relative effects of that damage on production remain unclear. Near wellbore damage impairs the formation 1s ability to conduct hydrocarbons to the wellbore Formation damage lowers well productivity, defers production revenues and is difficult to repair. A large number of formation damage mechanisms arising from the interaction of drilling mud solids and fluids with the reservoir solids and fluids can occur. Current field evaluation techniques to measure in-situ formation damage may lack the resolution to provide meaningful data on the extent of the problem. Reservoir conditions core flood tests provide a means to simulate the interactions that take place between the invading drilling mud and the formation. This allows measurement of the extent of the impairment and visualisation of the mechanism. The technique attempts to simulate, as closely as possible, the conditions occurring in the reservoir during drilling-in through the use of:–Real, used field muds sampled from previous drilling campaigns–Fresh, well-preserved core material from the target reservoir, and if possible, original native pore fluids, i.e., both pore water and hydrocarbons–Realistic, long-duration core exposure to the drilling fluid under reservoir conditions, with mud flow past the core face at realistic borehole velocities–Measurement of formation damage by crude oil return permeability determination after simulated back production under drawdown P. 101