The increasing number of horizontal wells being drilled, together with the continuing development and use of open hole completions has resulted in increasing reliance on formation damage testing to select the appropriate drilling fluid and/or cleanup technique. A two-year laboratory study was conducted to evaluatenear wellbore invasion and related damage due to two typical Drill-In fluids (D.I.F.) andperformance of various cleanup procedures using specific "breakers". In the first part of the paper, values of Flow Initiation Pressure (F.I.P.) and return permeability measured on rock samples damaged with an Oil-Based Mud (OBM) and with a Water-Based Mud (WBM) are compared to evaluate the self cleaning properties of sandstone core samples having a large permeability contrast. In the second part, the performance of various "breakers" (mutual solvent, emulsified acid, surfactants for OBM, oxidizers and enzymes for WBM) is presented. Results show that the OBM present better filtration properties and is less damaging than the WBM. The general trend is that near wellbore return permeability (0–10 cm) and self cleaning properties are strongly related to the Jamming Ratio (Mean pore throat diameter/mean mud solids diameter). The use of OBM breakers may induce additional damage if the soaking time is not carefully controlled. On the other hand, WBM breakers may be efficient if they are used under optimum conditions. Finally, some recommendations are given for designing a low-damaging D.I.F. and to define, if necessary, the best cleanup procedure. Introduction Horizontal wells are being utilized throughout the world in an ever increasing fashion to attempt to increase production rates by targeting multiple zones, maximizing reservoir exposure, reducing drawdowns to avoid (or to minimize) premature water or gas coning problems. Formation damage in horizontal wells is a matter of great concern, specially for oil wells that have been open hole completed. In such a case, relatively shallow damage, which is not by-passed by perforations, can result in very large skins. This is a critical point for oilfields developed in deep water reservoirs where acceptable development costs are based upon a limited number of high productivity wells1. The economic impact of near wellbore formation damage in horizontal wells has pushed towards the development of number of theoretical and experimental studies2–6 to assess drilling induced formation damage and to evaluate the performance of various cleanup procedures. However, mechanisms of drilling fluid damage and filter cakes cleanup are not well understood and laboratory methods for determining the type and extent of formation damage potential are not standardised. Recently, a comparative study presented by Marshall et al.7 showed that formation damage test results should be treated with considerable caution since a good level of repeatability and/or re productivity has not been achieved. This paper is a contribution to understand physical processes which take place during mud invasion, filter cake removal by natural production and/or cleanup treatment. Our primary objective was to provide insights to answer the following questions:how may vary drilling mud damage and natural filter cake removal with the reservoir permeability and the nature of the mud (OBM vs WBM)?Is it always necessary to use a breaker to destructurate the filter cake and for increasing the productivity of a long horizontal open hole well?

Many fields in South East Asia are suffering from sand production problems due to sensitive sandstone formation. Sand production increases with time and increasing water production. The production of sand induces loss of production, due to sand accumulation in the wellbore, and heavy operational costs such as frequent sand cleaning jobs, pump replacements, replacement of surface and downhole equipment, etc. An original sand control technology consisting of polymers injection and already deployed in gas wells, has been successfully tested in an offshore oil well. The technology utilizes polymers having a natural tendency to coat the surface of the pores by a thin gel-like film of around 1 µm. Contrary to the use of resins which aim at creating a solid around the wellbore, the polymer system maintains the center of the pores fully open for fluid flow, thus preserving oil or gas permeability while often reducing water permeability (a property known as RPM for Relative Permeability Modification). The advantage of such system is that the product can be injected in the bullhead mode and often, a reduction of water production is observed along the drop in sand production. In gas wells, the treatment lasts around 4 years and can be renewed periodically. A lab work was undertaken to screen out a polymer product well suited to actual reservoir conditions. We conducted bulk tests to evaluate product interaction on reservoir sand samples, and corefloods to evaluate in-situ performances. Treatment volume and concentration were determined after lab test. One of "Oil Well" candidate is located in Arjuna Field, offshore Indonesia. Downhole conditions are: Temperature = 178°F, salinity = 18000 ppmTDS, permeability = 140-300mD, two perforated intervals with total thickness of 67ft (ft-MD) with 38 ft Average Netpay Thickness, production rate = 800 bfpd. The well is under gas lift and needed to be cleaned out every 3 months because of sand accumulation. Polymer treatment was performed in two stages (bottom, then upper interval). A total volume of 150 m3 of polymer solution was pumped. Immediately after treatment, sand cut dropped from 1% to almost 0%. This enabled increasing the drawdown from 32/64’’ choke to 40/64’’, keeping the production sand free and sustained with time. This field test confirms the feasibility of the original sand control polymer technology both in gas wells and in oil wells, which opens high possibilities in the future.

Several fields in South East Asia are suffering from excessive sand production due to clayey unstable reservoir rock. Sand production induces undesirable phenomena such as production loss due to sand accumulation in the well, damage of the pump and of the surface equipment, frequent well shut-in and heavy costs for cleanout jobs and pump changes. The operators are looking for an easy and cost-effective technique that could be deployed in the field, if possible rigless. In a previous paper5, a pilot treatment consisting of specific water-soluble polymer injection showed good results in terms of sand production reduction and preservation of well performances. The polymer adsorbs strongly on the reservoir rock, forming a continuous film on pore walls. The film has a consistency of thin sticky gel stabilizing the rock. Moreover, the polymeric film acts as Relative Permeability Modifiers (RPM) and thus maintain oil permeability while reducing water permeability. This RPM property enables the deployment by bullhead injection into the whole open interval. Field extension has been scheduled and similar treatments have been performed in 4 new wells. In the field, the polymer is injected by coiled tubing in each open interval selectively. The polymer is pushed in the formation by diesel/water postflush, which also re-saturates with oil the near-wellbore area and help production re-start. The feedback obtained so far can be listed as follows: No production loss occurred in all the treated wells.Sand-free production rate could be increased after the polymer treatmentSand production was totally stopped for a few months before coming back again after 4-12 months, at much lower rate than before.A re-treatment induced new period of sand-free production for several months. Such results confirm the sustainability of the polymer technology. The field methodology has been optimized. It opens new perspectives and could become a new sand control system in the toolbox of the profession.