Gullfaks has been in production since 1986 and produces approximately 11 500 Sm 3 /d oil from three Condeep platforms. The average water cut is approximately 75 to 80% and GOR of approximately 200 Sm 3 /Sm 3 . It has been estimated that between 50 to 100 tonnes of sand is produced yearly per platform with approximately 60 to 70% of the wells in active production (around 90) are limited by sand production. The typically well completion is cased hole with selective production through perforated liners. Rock mechanics studies have shown that sand will be produced irrespective of well inclination and perforation design. On Gullfaks, the sand management strategy used has been to produce wells at "maximum" or "acceptable" sand rates. This strategy has led to significant gains in production although there are challenges with this approach that include choke erosion, sand removal from the separators and oil in water quality associated with discharge to sea. In response to this, Statoil have investigated different methods of retaining sand downhole by chemical sand consolidation, of which in situ calcium carbonate precipitation will form the basis for the paper. This technology involves squeezing into the near wellbore predefined concentrations of urea and calcium nitrate along with the enzyme urease. After application, the well is shut in during which the enzyme catalyses the decomposition of urea to bicarbonate that reacts with calcium to form calcium carbonate. The paper will provide details of the laboratory evaluation and, in particular, focus on the field results from the first ever application of this type. A low risk candidate well was selected that had a short perforated interval (19 m) and produced 88 Sm 3 /d oil with a water cut of 94 %. Results will be presented of the operation design and planning, logistics examination, thorough risk evaluation, and post-operation results with lessons learned.

Abstract It is well known that the porous media invasion by components of drilling fluids decreases near wellbore permeability and it is one of the factors that generate poor well productivity or injectivity. Permanent changes on the original permeability decrease well flow capacity and only can be evaluated after a well production test. The quantification of the difference, the damage, is defined as the mechanical skin. Among others, two particular factors contribute for mechanical skin during the drilling process: reduction on the oil or gas saturation by the drilling fluid filtrate and reduction on the effective porous throat size by bridging or aggregation of solids and other components. The measure of the damage, its extent and remedial treatments has been studied since a long time using the API linear flow cell and filtration tests. However, the results obtained with this equipment do not allow an effective quantification that could be applied directly to the field mainly because of the test geometry. In this study, a technique to quantify physically the damage has being evaluated, using a physical simulator composed by a X-ray transparent radial flow cell, hollow cylinder synthetic sand core sample saturated with mineral oil after full water saturation, the X-ray Computerized Tomography (CT) and a procedure to evaluate the permeability return. The invasion profile for water-base drilling fluid components were mapped after drilling simulation and the residual damage was quantified after an oil production period. The results of this study showed that: permanent changes occurred on the porous media structure, which incorporated drilling fluids components at the grain and oil saturation was dramatically reduced. Both damages were not removed with the reverse flow of oil, generating a relative oil permeability reduction that was calculated in terms of mechanical skin associated. Introduction The resistance to flow and consequently increase of the differencial pressure needed for fluid drainage in a porous media is controlled by the porous geometry, fluid viscosity and fluid velocity. This relationship for linear or radial flow is well defined by the Darcy's law. An additional resistance to flow around the wellbore is given by changes in the porous size due to confinement forces or invation of particles or drilling fluid components. These changes will depend on the drilling, completion and production practices. Van Everdigen 1 defined skin as the additional resistance to flow that reduces the capacity of production in oil wells. Hawkins 2 formulated a mathematical equation that relates the skin effect with the affected radius and permeability of the damage zone. Hurst 3 et al showed mathematically how to overcome the difficulties found in the application of negative skins. They assumed that the effective radius of the wellbore went larger than the radius of the well in subject and modified the existent mathematical solutions to include this effect. Also, a positive skin can be treated in the opposite way. Person 4 et al concluded that the skin damage for a formation around the wellbore in horizontal wells can severely reduce the production of gas, especially when the ratio between the length of the well and the surface of drainage is small and the vertical permeability is high. Parn-Anurak and Engler 5 developed a method that simulates the invasion of the drilling fluid in a two-phase system and evaluates the damage in the wellbore. The model proposed includes filtrate invasion, filtercake formation, and relative permeability components. The filtrate and filtercake models were developed based on the equations of mass balance and Darcy and the system was solved numerically to characterize filtrate invasion. The simulation results anticipate the distribution of filtrate, indicate the maximum depth of invasion and also the invasion profile for the drilling fluid components near the wellbore. The method improved the characterization of the filtrate and the damage estimation along a horizontal well. The principal objective of this paper is to propose a methodology to evaluate the mechanical skin in a radial flow. The paper analyzes the damage generated by the invasion of a water based polymeric drilling fluid into the synthetic core samples and estimates the skin factor and the permeability reduction.

Abstract A unique test configuration has been utilized to investigate the flow-back properties of oil-based fluids through sand screens for openhole completions after 1–2 months suspension time. This test which simulates downhole conditions can be used to select fluid in which the screens will be suspended. The results from the testing show that oil-based fluid with a density greater than 1.5 sg can plug the sand screen if suspended for a long period. The results show the effect of both time and temperature on the plugging tendencies. Increased temperature and time increases the risks of plugging. The use of low-solids oil-based fluid has proven to reduce the probability of plugging and will be recommended at higher fluid densities. This paper will outline the test set-up as well as present the findings from running more than 50 different tests on different fluids. These fluids include conventional oil-based and low-solids oil-based drilling fluids at varying densities tested at temperatures from 95 to 175°C. Introduction When wells are to be openhole completed, there are often questions about which fluid system to leave in the well when the screens are run into the well. Logistically it will always be easiest to leave the drilling fluid used to drill the section in the hole. Sorgard, et al.[1] described an apparatus to allow wellsite testing of flow-back properties of drilling fluids through the screen to ensure that the drilling fluid will not plug the screen. However, if the drilling fluid density is high there can be a high amount of solids in the drilling fluid system. If the wells are left for long periods before put on production, the solids tend to settle out and cause problems with clean-up when starting the production. As following this can give plugging of the production screens. This paper presents the test apparatus and results for over 50 oil-based drilling fluids with various solids loading, density and temperatures of heat aging for several months to simulate long-term downhole conditions. If the wells are drilled with water-based drilling fluid, displacing the open hole to heavy brine-based fluid with minimum amount of solids will be the obvious solution. However, if the wells are drilled with oil-based drilling fluid, displacing to a near-solid-free brine before running the screens is not advisable due to the potential formation damage caused by emulsion blocking when oil-based drilling fluid filtrate is mixed with brine. In addition, hole stability can be affected when displacing from oil-based fluid to a water-based completion brine. In these situations the Low-Solids Oil-Based Drilling Fluids, or "Mud", (LSOBM) can be an alternative for the completion phase. Taugbøl, et al.[2] presented this LSOBM-type of fluid for use in openhole completion. In these fluids the density is given from an internal phase of heavy brine. Depending of the required density, expensive heavy brines like cesium formate are required to achieve a near-solid-free fluid, but in turn drives the cost of the fluid system to extreme levels. This work presented has therefore focused on wells where oil-based drilling fluid has been used for drilling the well and then displaced to fluid with an acceptable solid content. Different oil-based fluids have then been tested for screen flow-through characteristics after a given aging period at given temperatures in order to find the optimal solution for given situation. The objectives of the testing are to find correlations between mud weight, solids content and the ability of the fluid to flow through the screen. Certain rules of thumb have been used when selecting fluid to leave in the open hole before screens are set in place. Guidelines based on actual experiments are obtained from this testing.

Abstract During well drilling operations, the invasion of the porous media around the wellbore by a certain quantity of drilling fluid components is likely to happen to build a stable mudcake. For a horizontal open hole well, the mud cake is kept during drilling and completion operations giving stability to the borehole. Because the drilling fluid is heavier than the formation fluids, solid particles and fluid components are pushed into the formation establishing a filtration process. At some point, the mud cake must be removed and a clean up procedure is done. For production wells, the majority of the mud cake and invaded components are removed with the well production and the resulting skins are usually acceptable without any secondary treatment. However, for injection wells, such removal is always a problem and special treatments are needed. The success of such treatments is based on the knowledge of the invasion profile and their composition. Therefore, a better characterization of the invasion profile could improve substantially the clean up procedures and the treatment selection. In this first result the aim of study is to address this problem an experimental procedure was developed to identify and characterize the profile of drilling fluid invasion. This technique used the X-Ray Fluorescence Beam line (XRF) from the Synchrotron Light at the Brazilian Synchrotron Light National Laboratory (LNLS) in Campinas, São Paulo State, Brazil figure 1. This methodology allowed the determination of the invasion profile in synthetic unconsolidated sandstones similar in composition to the reservoir rocks. Along with the invasion profile, µ-SRXRF analysis was used to map and identify drilling fluid components that may have invaded the core. The identification of these components provided information to differentiate and identify carbonates and polymers in terms of concentration and penetration. The results obtained constitute a unique source of data and highlight the reliability and applicability of the technique proposed. Finally, a dimensional analysis was used to estimate the invasion profile for a real horizontal well. Introduction During well drilling operations, the invasion of the porous media around the wellbore by components from the drilling fluid is likely to happen. Since the drilling fluid is usually heavier than the formation fluids, their components are pushed into the formation, establishing a filtration process and building a stable mudcake. For a horizontal open hole well, this mudcake is kept during drilling and completion operations giving stability to the borehole. Fluid loss while Drilling is a complex process in which significant part of the fluid is lost underneath the bit under continuous spurt conditions[1,2]. The spurt loss occurs where new surface area is being generated, i.e. where the rock is being crushed and removed. Drilled fines, sized calcium carbonate, modified starch (HPA) and viscosified polymers (xantham gum), are filtercake compounds that cover the borehole. This filtercake is beneficial since it can significantly reduce the fluid loss rate preventing further collapse to the wellbore. During the spurt phase, however, fluid enters the formation resulting in potential damage,[3]. The depth of the invasion and the reduction in permeability in the invaded zone will determine the skin and overal1 effect on production.

Abstract Calcium carbonate scale formation is a major drawback in oil or gas production wells, in geothermal processing equipments and in industrial cooling water installations. In most cases it reduces the overall fluid flow rate, induces formation or production damage and may lead to a shutdown of exploiting operations. Various chemical inhibitors have been proposed to inhibit scale deposits. A major challenge is the evaluation of their action in near real operating conditions. Usually effectiveness is evaluated by the analysis of residual scale inhibitor in brines. A novel approach is here proposed which uses an electrochemical technique to accelerate scale formation. Measurements on an electrode immersed in the tested water include as a function of time the decrease of the incident current (chronoamperometry) and the simultaneous increase of the weight recorded by a microbalance (chronoelectro-gravimetry) as a consequence of the progressive electrode surface coverage by scale deposit. By using a specific experimental device it is possible to follow and visualize in situ scale deposition or inhibition on a metallic surface under near-real hydrodynamic flow conditions. Introduction The precipitation of insoluble mineral deposits is a common cause of production damage in oil or gas production wells. Calcium carbonate scale formation is usually generated through up-hole degassing and loss of CO 2 in producers exhibiting more than 70% water production. The natural solubility of Ca ++ and HCO 3 - ion pairs is thus reduced by a pressure or temperature change in the flowing fluids. Calcium carbonate precipitation, contrary to other types of mineral scales such as sulfates of Ba, Ca or Sr, generally appears in the upper section of the production tubing and normally does not pose a threat to the actual formation. Major primary damages thus occur through filling of the production string and downstream through the inability of valves and safety equipments to function properly. Various remedial actions were investigated. Originally chemical HCl acid wash and mechanical scrapping were used to alleviate the damage. In very severe cases, tubing replacement was used. These methods were labor intensive, economically unacceptable and did not address the long term mitigation of the problem. Furthermore in the case of acid dissolvers many drawbacks were observed such as corrosion of carbon steel equipments, formation wettability inversion and physical plugging by fines generated by dissolution of cementing minerals, by clay swelling and by water blocks 1 . Since more than a decade threshold organic inhibitor treatments to prevent carbonate scale precipitation were proposed instead of concentrating on removal the scale after the fact. The major incentive was long term economic feasibility. Two methods of implementation of the inhibitor were considered : down-hole injection using high pressure low volume pumps and capillary tubing or inhibitor squeeze into the reservoir 2 . Although less risky down-hole continuous injection of inhibitor is found in most cases to be economically undesirable. The inhibitor precipitation squeeze is usually performed with a calcium overflush to cause precipitation inside of the formation of a 1% concentrated inhibitor solution. Slow release of the inhibitor in the production system is a function of its solubility. The risks of damaging irreversibly the formation are great. On the contrary the squeeze adsorption technique requires no calcium overflush, seems cheaper to perform and theoretically minimizes the chances of formation damage.