Crude produced in the North of Monagas Estate, East Venezuela, has a high asphaltene content, which comes out of solution in both the wellbore tubulars and pipeline. This can eventually lead to complete plugging of the pipeline. This increases the cost of maintaining production because of the need to periodically remove these organic deposits. In a specific case, 9 km of 8–5/8-in. outside diameter (OD) production pipeline was successfully cleaned out using 2-in. OD coiled-tubing (CT) to regain pipeline production. As there is limited literature or documentation on the use of CT for this specific application, the operator and the service company established a joint team to do the feasibility study and engineering. Some of the key points were; the design of a frame to lay down the injector head, define the entry points along the pipeline, the selection of the bottomhole assembly (BHA), and fluids to use. Other issues were the measurement of stresses (push/pull) on the CT so that the CT could be run as far as possible in the pipeline without damaging either the CT or the pipeline. The pipeline was successfully cleaned, the CT being run seven times from five different entry points in the pipeline. This resulted in savings of USD 1 million for the operator and significantly reduced the time to recover normal production in the pipeline. Background The characteristic asphaltene content in the crude produced from the northeastern Venezuelan oilfields,1 requires periodic CT cleanouts with solvents and mechanical means to remove the obstructions that plug the wells and reduce production. These asphaltenes precipitate from solution in the wellbore tubular, caused by the pressure and temperature differentials, and progressively reduce the flow area in the tubing. Surface facilities are not exempt from this phenomenon. As the crude flows through the pipeline, the asphaltenes settle at the bottom due to the lower temperatures and pressures in the system.To prevent total plugging, the operators pump solvent mixtures and pigs through the pipelines, however without regular treatments the pipelines become restricted and eventually the production rate drops. In the case studied, this phenomenon led to an increase in the differential pressure in the line and ended in complete production stoppage on the surface system. This forced the operator to look for alternative means to reestablish and maintain production. Fig. 1 illustrates the progressive increase in the pipeline's differential pressure caused by the asphaltenes accumulation. Conventional pipeline maintenance practices could not be performed. Pumping aromatic solvents was not an option given the environmental constraints. Temporary Production Assisted by a Mobile Testing Unit To maintain the well's production, a program designed to produce the well using a mobile testing unit (MTU) was implemented. A choke manifold, a flare, two separators, and twelve 500-bbl capacity storage tanks were connected to the well and reconnected to the production line. Because of the severity of the pipeline plugging, it was necessary to transport the produced oil using trucks, increasing the risk associated with human error and environmental incidents. Fig. 2 illustrates the MTU layout. An attempt was performed to unplug an entire pipeline section, with the assumption that the plugged section would be below the river crossed by the pipeline, as this was the coldest and the lowest point in the pipeline. Two pipeline entry points (HT1 and HT2) were constructed to perform a first test across the river section by pumping water at a maximum pressure of 2,900 psi. Different pipeline sections were tested following the same procedure. When the pressure built up and there was no resultant flow at the other end, a plugged section was identified. Two main plugged sections were identified. The results showed that these plugged sections were located between the pipeline entry points HT3 and HT2 and between HT1 and HT4. Fig. 3 illustrates the pipeline layout on the field and the pipeline entry point locations.
Proposal Compaction drive is a potentially important recovery mechanism for weakly cemented heavy oil reservoirs. In order to assess its magnitude the knowledge of the compressibility of the reservoir sands is required. However, due to the very nature of this class of reservoirs, the reliability of laboratory measurements can be questioned as the specimens are heavily disturbed during the coring process. To circumvent this shortcoming, the option of carrying out in-situ compressibility measurements becomes attractive. The use of a dilatometer, allowing the downhole measurement of the pressuredeformation characteristics of the formation, has thus been considered. A preliminary study was carried out involving direct numerical simulations of a dilatometer test in a sand described by a Cam-Clay model. That study showed that the mechanical parameters, in particular the elastic and plastic compressibilities as well as the consolidation pressure do affect the response, thus establishing the theoretical feasibility of such a measurement. A series of three tests were conducted in a newly drilled well in an uncemented sandstone reservoir. By applying an inversion technique, based on an iterative finite element algorithm, it is then possible to identify the Cam-Clay parameters of the formation sands.
Hardbanding materials are used to protect tool joint drillpipe against wearin drilling operations. Hardbanding shall resist wear in openhole conditions with a minimum damage to upper casing. Laying down drillpipe for hardbanding repair can significantly increase rig time and tubular costs. All hardbanding products applied for Sincor were wearing out completely after drilling 15,000ft in 50 hours in the reservoir. It was necessary to search for new hardbanding alternatives with an extended lifetime. A field evaluation program was designed to compare wear resistance of different commercial hardbanding materials and toevaluate new techniques for welding tungsten carbide pellets with alloyingwires and for testing of tungsten carbide spheres being laser applied. Hardbanding products were selected upon analysis of wear mechanisms occurring in drillpipe while drilling horizontal wells in Sincor. Wear resistance was monitored in terms of cumulative drilled footage until gauging complete wear ofhardbanding on tooljoints. One of the newly developed hardbanding products wasfinally selected as the best option after considering its superior wear resistance, minimum expected casing damage, and moderate cost. This is thefirst reported successful application of tungsten carbide pellets welded withina hard matrix provided by an alloy wire for hardbanding purposes. Introduction Wear of drillpipe is an important issue for drilling operations in Sincorarea. Wear increases operational cost due to repair of components, rig time tochange out worn down components, and lost of valuable tools. Wear of components has been reported in the tool joint drillpipes since start of operations.Hardbanding and repair cost for a 5,000-ft string can reach up to US$ 150,000 over the string lifetime. With this amount of money and time invested in wear control, high consideration was given to develop material specifications for requesting wear resistant materials. Other solutions implemented in Sincor toreduce drillstring wear are the following:Use of down-hole tools, i.e. Hydroclean drillpipe, for better hole cleaning and a consequently reduction of the backreaming while drilling horizontal sections.Optimization of drilling practices such as mud circulation, use of Hi-Vispills, and backreaming parameters.Use of mud additives, i.e. Ecolane solvent, and heating the mud to reducedrillstring friction.Use of several types of hardbanding materials. This work is aimed to find the most appropriated hardbanding material forprotecting drillpipes in openhole conditions. Minimum casing wear and environmental pollution due to chromium discharge within the drilling fluidswere identified as special concerns. Background Sincor is an operating oil company created in 1997 and it is comprised by Total Venezuela S.A., PDVSA Sincor S.A., and Statoil Sincor A.S. The company started operations in 1998 to exploit the Zuata reservoir located in the Orinoco Belt in Southeastern Venezuela. Reservoir is characterized by an 8-°APIheavy crude oil in unconsolidated sand with extensive shale bedding. Wells are drilled in clusters to minimize environmental impact. Each cluster has an average of 12 extended reach wells having an average horizontal section of 4,450-ft in length. Frequent backreaming is required for hole cleaning purposes. This combination of unconsolidated sand and repeated backreaming as depicted in Figure 1, are the primary causes for wear of drillstring components. Drillpipe is laid down when tooljoint outside diameter is lower than 6–3/8".
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