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.

The conceptual idea is to give the porous matrix of the formation some additional residual strength to enhance the maximum sand free rate (MSFR). Sand production in weakly consolidated reservoirs will occur when tensions in the well/perforation tunnel walls are large enough to disrupt the binding between the individual sand grains. This will generate a plasticized layer of sand in the near well bore area. The layer will erode by the produced fluid and be transported to the surface. The rate of erosion will depend on the residual strength of the plasticized zone and of the hydrodynamic forces acting on that particular zone. There is field evidence indicating a residual strength corresponding to the capillary force in water-wet sand to be sufficient in stopping or limiting the sand production substantially. Thus, only a small increase in residual strength of the plasticized sand would make large contribution for enhancing the MSFR. This will have large economical implications in fields with wells controlled by MSFR, and particularly in the decline phase in which the field is well controlled by the well potential. Since the criteria for strength are quite low, search for potential treatment chemicals could be carried out in areas completely different from the traditional chemicals used in sand consolidation. Three different chemical systems have been investigated and one chemical has been brought further for laboratory qualification and field use at a North Sea Field. In order to carry out a full field test, challenges regarding water contamination, long horizontal wells with difficult placement and zonal coverage, and complex polymerization mechanisms in the carrier fluid had to be addressed. Some of these challenges and field experiences will be presented and discussed to gain valuable knowledge for future chemical sand consolidation operations. Introduction Sand production from oil and/or gas producing wells is a problem in many parts of the world [1–3]. Sand production causes erosion of process equipment and disposal of the sand causes environmental problems, especially offshore.The active sand control has mainly focused on screens [1, 4–8], gravel packing [9] and perforation techniques [10, 11] to prevent sand production. All these methods include heavy hardware and tools being a large part of the cost of a new well. For poorly consolidated formations, chemical sand consolidation can be an alternative to the traditional techniques. In particular for sub sea developments where conventional interventions are expensive, chemical methods can be a competitive remedial alternative. Chemical sand consolidation has been in use since the early 1940's [12]. Quite a lot of research has been done on epoxy and furan systems, especially in the 1960's [12–21]. The prior art of chemical sand consolidation is to make "rock" from sand, in other words to increase the strength of the matrix to a large degree. The basic idea of the present work is to only increase to the residual strength of the formation by a small amount. In order to prove this new idea, a laboratory study was undertaken to evaluate different chemicals for sand consolidation. The chemicals used can be divided into three different groups based on the consolidation method:Chemicals that are based on organosilane chemistry,chemicals based on polymers andan enzyme derived method based on precipitation of CaCO3 (s). The chemicals were tested with regard to their ability to reduce sand production compared to reference experiments. The best overall chemicals for sand consolidation seemed to be the organosilanes. These chemicals aim at reducing the effect of tensile failure and hydrodynamic erosion of the formation matrix, two aspects of sand production that are especially important for unconsolidated formations. One of the organosilanes was further qualified for field application.

The conceptual idea of chemical sand consolidation is to give the formation some additional residual strength in order to enhance the maximum sandfree rate (MSFR). Sand production in weakly consolidated reservoirs will occur when stresses in the well/perforation tunnel walls are large enough to disrupt the binding between the individual sand grains. This will generate a plasticised layer of sand in the near well bore area. The layer will erode by the produced fluid and may be transported to the surface. The rate of erosion will depend on the residual strength of the plastified material and the fluid rate. There is field evidence indicating a residual strength corresponding to the capillary force in water-wet sand to be sufficient in stopping or limiting the sand production substantially. Thus, only a small increase in residual strength of the plastified sand would make large contribution for enhancing the MSFR. This will have large economical implications in fields with wells controlled by MSFR. As the criteria for strength are quite low, search for potential treatment chemicals could be done in areas completely different from the traditional chemicals used in sand consolidation. Three different chemicals have been investigated and one has been brought further for laboratory qualification and field use. An important property is that the treatment system is oil-soluble. In contrast to water soluble systems, it will not alter the relative permeability in the oil bearing zones, thereby reducing the risk of increased skin due to changes in saturation. This oil-soluble system will be beneficial in fields with low reservoir pressure. The method is employed by simple bull-heading and will have a kind of self-diverting property. A team of engineers and scientists from different Statoil organizations were put on the job. New challenges regarding high water contamination, wells with difficult placements and zonal coverage, and a complex polymerization mechanism in the carrier fluid had to be solved. These experiences will be presented and discussed to gain valuable knowledge for future chemical sand consolidation operations. In this paper, the experimental data and field applications will be presented. In one well, oil production was doubled as a result of the treatment. Introduction Sand production from oil- and gas wells is a major problem in many parts of the world [1–3]. There are many problems associated with sand production, both regarding HSE (Health, Safety and Environment) and operational aspects. When sand is produced at a high velocity, it can cause erosion on any metal surface on its way. This is especially true for bends, valves and other points with a sudden change in flow direction. Erosion of process equipment can be a safety problem, but there is also an economical issue. Special care has to be taken when selecting materials at the points where erosion is a problem. The produced sand is usually captured in the first-stage separator and has to be jetted out. Furthermore, fine sandparticles might also influence on the separation efficiency of the process train topside. Why is sand produced? Many reservoirs are poorly consolidated, and both gas- and oil producing wells can experience sand production [4–6]. Changes in the stress conditions in the reservoir can lead to failure of the rock. A plastified zone is created and the fluid flowing in the well will erode this zone and bring the sand grains into the well. If the fluid velocity is high enough, the sand will be transported all the way to the surface. A rock failure is prerequisite for sand production, e.g. the fluid flow itself will not have enough energy to break loose the sand grains from the formation.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe conceptual idea is to give the porous matrix of the formation some additional residual strength to enhance the maximum sand free rate (MSFR).Sand production in weakly consolidated reservoirs will occur when tensions in the well/perforation tunnel walls are large enough to disrupt the binding between the individual sand grains. This will generate a plasticized layer of sand in the near well bore area. The layer will erode by the produced fluid and be transported to the surface. The rate of erosion will depend on the residual strength of the plasticized zone and of the hydrodynamic forces acting on that particular zone.There is field evidence indicating a residual strength corresponding to the capillary force in water-wet sand to be sufficient in stopping or limiting the sand production substantially. Thus, only a small increase in residual strength of the plasticized sand would make large contribution for enhancing the MSFR. This will have large economical implications in fields with wells controlled by MSFR, and particularly in the decline phase in which the field is well controlled by the well potential.Since the criteria for strength are quite low, search for potential treatment chemicals could be carried out in areas completely different from the traditional chemicals used in sand consolidation. Three different chemical systems have been investigated and one chemical has been brought further for laboratory qualification and field use at a North Sea Field.In order to carry out a full field test, challenges regarding water contamination, long horizontal wells with difficult placement and zonal coverage, and complex polymerization mechanisms in the carrier fluid had to be addressed. Some of these challenges and field experiences will be presented and discussed to gain valuable knowledge for future chemical sand consolidation operations.

The success of a scale inhibitor treatment depends on the 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 potentially 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 interval 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. As a result of this work a fully viscosified scale inhibitor system is developed. 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 at Heidrun field in one long deviated well, all with significant permeability variations and cross flow. The operations were successful and the scale treatments have protected the wells from scaling. The paper describes the product qualification process, placement simulation, temperature prediction and gel breaking characteristics, case histories and post job evaluation. Introduction Both Norne and Heidrun fields have placement challenges regarding scale protection of long horizontal wells. Often these wells have significant permeability and pressure variations along the well bore. Norne is a sub-sea field with a combined production and storage vessel, FPSO (Floating Production, Storage and Offtake) connected to 14 production and 8 sea water injection wells from 6 sub-sea templates. Hence, all major well operations need to be performed using rig or intervention vessel. Well operations are therefore limited by access to rig/vessel and by weather conditions. The field is located at the Haltenbanken area 200 km offshore Mid-Norway and north of the 66th parallel (Fig. 1).