This paper was prepared for presentation at the 1999 SPE European Formation Damage Conference held in The Hague, The Netherlands, 31 May–1 June 1999.

Summary We investigate the invasion of solids and their mobility during cleanup. We study the effect of weighting agent particle size on rock substrates of varying permeabilities. We find permeability damage increases but flow initiation pressures decrease with increasing substrate permeability. We obtain quantitative profiles of solids invasion by scanning electron microscopy/x-ray mapping and synchrotron energy-dispersive x-ray diffraction tomography. We compare these profiles to core sectioning data. We find invasion profiles drop steeply but fines are observed deep within the core. We examine the effect of backflooding on the invasion profile. Near-surface damage is reduced but deeply invaded fines are unaffected by backflow. We develop a deep bed filtration model for solids invasion and consequent permeability reduction. This model is compared to the profiles obtained in the invasion experiments. We find that we can fit the experimental invasion profile for monomodal particles using a single trapping coefficient. Backflow is modeled by reversing the flow rate. We postulate a phenomenological rate of erosion to untrap particles in line with experimental observations (30%). When erosion is included in the model, a peak in the backflow pressure is found. This peak may be correlated with the experimentally observed flow initiation pressure. Introduction Well productivity is critically important if oil and gas reserves are to be developed economically. With the change in economic climate and the maturation of many existing fields has come an emphasis on reduced production costs and optimized productivity. The trend towards openhole completions places additional emphasis on damage avoidance. Near-wellbore permeability impairment from drilling and completion fluids can have a substantial, yet potentially avoidable, impact on well productivity. The proper design and engineering of fluid systems to minimize productivity impairment is therefore important. The fundamental mechanisms involved in formation damage by drilling fluids and its remediation have been investigated as part of a research collaboration between Schlumberger Cambridge Research and the Institut Franc¸ais du Pe´trole and Statoil under the auspices of the EC-Joule Programme.1 In this paper we report studies of particulate invasion and its impact on production. Particulate invasion is one of the primary causes of formation damage from drilling fluids. During the initial stages of filter cake growth particles are forced into the formation, building an internal filtercake which plugs the near surface pores. Removal of this internal cake can be difficult, and can lead to reduced permeability. The importance of minimizing internal filter cake is widely recognized. Most attention has focused on the selection of an appropriately sized weighting agent to bridge across surface pores, thereby minimizing spurt loss.2 Alternative bridging approaches such as the use of structured fluids3 (for example, mixed metal hydroxide-bentonite systems) have also been explored. Despite these efforts, the minimum spurt is not zero and some internal cake does form. This invaded material can be quite tenacious. Francis4 reported significant damage from shallow invasion even after removal of external filter cake. Better understanding of the properties of both the internal and external cake is needed for improvements in drill-in fluids. Visualization has been seen as an important step in understanding the mechanisms of permeability impairment determined through core flood testing.5 However as van der Zwaag observed,6 quantitative analysis of invasion is a much more powerful tool for assessing formation damage, giving information which can ultimately be used to develop predictive models. A number of different approaches have been pursued,5–8 ranging from electron microscopy and x-ray analysis, to chromatic tomography (CT) scanning and nuclear magnetic resonance (NMR) imaging. All have their advantages and disadvantages; some are destructive, while nondestructive techniques often cannot resolve features at the individual pore level. Here we report studies of particle invasion using two techniques: scanning electron microscopy energy-dispersive spectroscopy (SEM-EDS) x-ray mapping, and energy-dispersive x-ray diffraction tomography using a synchrotron source (synchrotron EDD-T). In this paper we report experimental studies on invasion and bridging with particulate weighted fluids and the effect on permeability damage. We locate and profile the damaged zone using different analytical techniques and quantify the effect of cleanup by backflow. Finally we describe a deep bed filtration model of solids invasion and consequent permeability reduction. This model is compared to the invasion experiments. Experimental Methods Formation Damage Measurements. Formation damage measurements were made with three different test configurations. Detailed descriptions can be found in Refs. 1, 3 and 8. Each permitted the in-situ determination of the core permeability before and after exposure to drilling fluids. Two are based on API high pressure-high temperature (HPHT) filtration cells modified to take core samples,3L×d is either 8×38 or 32×25.4 mm with a flat-blade impeller to provide shear for dynamic filtration conditions. The third8 uses long cores of L×d of 190×40 mm. Pressure taps along the core holder at ?5 cm intervals allow direct spatial resolution of the permeability impairment during and after filtration. Before use, cores were vacuum saturated with brine simulating connate water from the Heidrun reservoir. Permeability to brine was measured at a minimum of three flow rates. Unless stated, filtration was conducted for invasion of 1 pore volume under 20 bar differential pressure (in the opposite direction to the permeability determination) and at ambient temperature (23°C). After filtration, permeability to brine was again measured to give the percent of retained permeability. As backflow is imposed, a peak in the pressure is observed. This is defined as the flow-initiation pressure (FIP).9 The accuracy of measurements on short and long cores (32×25.4 and 190×40 mm) was ?1% and reproducibility 5%. Tests with the thin rock slices were less accurate; 10 to 20%. Rock substrates with different permeabilities were used. The majority were sandstones with minimal clay content. Our primary substrate was Clashach sandstone. A polymer-based fluid was used; its formulation is given in Table 1, with different grades of barite and carbonate weighting agents, and particle size data given in Table 2. SEM-EDS Mapping. We used a Philips XL30 SEM equipped with a motorized sample stage and a Noran Voyager energy-dispersive spectrometer. The external filter cake was removed and cores were carefully fractured before air drying for analysis.

Summary The success of a scale inhibitor treatment depends on placement efficiency. The scale inhibitor should be placed so that all water-producing intervals accept a sufficient quantity of the total treatment volume. If significant permeability or pressure variations are present in the interval to be treated, treatment fluid will enter the zones with the higher permeability and lower pressure, leaving little fluid to treat the other zones, which can be the water- producing zones. The challenge is even greater in long, horizontal wells with significant permeability and pressure contrast. To achieve a more uniform fluid coverage, the original flow distribution across intervals often needs to be altered. The methods used to alter this are called "diversion" methods. The purpose is to divert the flow from one portion of the interval to another. In response to this challenge, a joint study with the objective of improving the placement of treatment fluids was initiated by a major operator in the North Sea and two service companies in 2002. The joint work resulted in development of a fully viscosified scale inhibitor system. The system comprises a purified xanthan viscosifying agent, a standard scale inhibitor for downhole scale squeezing, and a breaker to achieve controlled gel breaking down hole. The system has been field tested at Norne field in two long horizontal wells and at Heidrun field in one long deviated well, all with significant permeability variations and crossflow. The operations were successful and the scale treatments have protected the wells from scaling. This paper describes the product qualification process, placement simulation, temperature prediction, gel breaking characteristics, case histories, and post-job evaluation.

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When a typical oil reservoir reaches its economic limit after primary and secondary recovery (water flooding), the world average says that more than two thirds of the original oil is left in place1. The challenge is to develop Enhanced Oil Recovery (EOR) methods that ensure an economical tail end production from these fields. Today's oil price is very high resulting in better economics for EOR-concepts. There is now a trend in the business that companies again are doing research and development in this area. Secondary water flooding leaves the residual oil capillary trapped. Surfactant injection can mobilize this residual oil by a strong reduction in the interfacial tension (IFT) between oil and water. However, a combination of polymer for mobility control, a small bi-functional molecule for enhanced solubility and reduced effect of salinity, and surfactant to lower the IFT will according to the theory have a much better effect as a tertiary oil recovery method. The concept is to search for a robust type III phase system. A polymer, a surfactant and a small bi-functional molecule in combination has been given the tentative name of "COMB-flow". Laboratory experiments with this COMB-flow system indicate an increased recovery of OOIP by 20%. The residual oil saturation was lowered by 12% and the residual oil recoveries ranged between 30.5% and 37.3%. Relative to the recovery obtained after traditional water flooding the recovery is enhanced almost 50%. These results were obtained on a crude oil having the in situ viscosity of 3.5 mPas at reservoir temperature. The experiments were performed at reservoir conditions. This system will be tested further on effects on different crude oils. Furthermore, different flow regimes will be tested. Introduction The use of crude oil plays an important role in the world economy today. The International Energy Agency states that petroleum products still will be the world's most important source of energy for the next 30 years. The world's demand for energy will increase by 50 percent the next 25 years. The production rates of the 100 largest oilfields in the world are all declining from plateau production2. When a typical oil reservoir reaches its economic limit after primary and secondary recovery (water-flooding) more than two-thirds of the original oil is left in place1. The challenge is to develop EOR methods that ensure an economical tail end production from these fields. Water-flooding leaves the residual oil capillary trapped. This is illustrated by the oil droplet in the upper part of Fig. 1. Surfactant injection can mobilize this residual oil by a strong reduction in the interfacial tension between oil and water as shown in the bottom part of Fig. 1. However, reduction in IFT might not be enough. A combination of low IFT and increased displacement fluid viscosity might be required. Mobility control. During a standard water-flood, the sweep efficiency achieved is usually not as good as desired. A fingering effect of the water-flooding into the oil bank or surfactant slug as can be seen in Fig. 2 could be a usual problem. At the top (a), water is fingering into the oil bank. At the bottom (b) the use of a polymer has reduced the effect of fingering significantly. By avoiding fingering and achieving piston-like displacement the volumetric sweep can be improved.