Most of PETRONAS fields in Malaysia have been producing for more than 20 years. At this advanced stage of depletion, reservoir driving forces are low. Organic deposition, particularly in the near-and-around well bore region and in production tubing, can further reduce the production of oil by restricting the flow passage from reservoir to wellbore. A study to address this issue with a view to rejuvenate the problem wells through laboratory analysis & pilot field implementation was conducted. A unique thermo-chemical system has been developed as an effective tool for 1:Removing the organic deposits near-and-around wellbore and production tubing, henceEnhancing the production from the treated wells. The two components of the system are injected simultaneously into the wellbore through production tubing. Upon mixing, both components will produce heat and reaction products. The heat generated capable to melt and dislodge the organic deposits. While, the reaction products will act as an effective solvents and surfactants for dispersion of organic species. The objective of this paper is to present the result of 4 wells treated by the thermo-chemical system. Well selection criteria based on production profile and well history is described. The implementation technique and a post treatment production gain are also highlighted. INTRODUCTION Crude oil is a complex mixture of various hydrocarbon components. Under reservoir conditions of high temperature and pressure, the crude oil components exist in two phases (liquid and gaseous) under thermodynamic equilibrium with connate water attained over geological times. Heavy hydrocarbon components such as asphaltenes, resins and waxes, which at normal surface conditions are solids, exist in solution, either colloidal or disperse form, in liquid hydrocarbons. Similarly, light hydrocarbons which are in gaseous form under normal surface conditions, exist in solution and vapour forms under equilibrium with each other. When a well is put on production, the produced liquid and gaseous phases (water, oil and gas) are subjected to lowering temperature and pressure along production pathway and as such pass through a continuum of dynamic phase equilibrium. As a result, oil soluble solids (asphaltenes, resins and waxes), water soluble solids (scales) and soluble gaseous start separating out from the produced oil. These separated/precipitated organic solids under favourable hydrodynamic conditions have the ability to agglomerate, grow in size and diffuse from bulk to interphases (rock surfaces and pipe walls) and form deposits. The produced formation fines (sand, silt, clay etc), water borne scales and fine corrosion product can get oil wetted and act as excellent nuclei for the initiation and growth of organic deposit particularly waxes. Therefore, the actual oilfield deposits are composed of organic solids, scales, formation fines and trapped oil. The organic deposit can be predominantly parrafinic or asphaltenic in nature depending upon the nature of crude oil, change of temperature and pressure equilibrium, production rate, etc. The deposition can take place at all locations along the production pathway viz-a-vis around wellbores, in production tubings, surface facilities, flowlines, pipelines and storage tanks. Deposits around wellbore (causes formation gdamage reflected by high skin for the well) and in production tubing, adversely effect the well productivity.

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Block X of offshore Sarawak consists of stacked and multi-layer reservoirs that produce gas, condensate and oil where the production is in-commingle from many wells. 47 surface PVT samples were taken and analyzed from every reservoir during the exploration and initial production periods. Despite the number of samples and a series of PVT studies had been conducted, fluid PVT and its reservoir modelling application remain an uncertainty for Block X. Therefore, a comprehensive 3-phase PVT study was conducted, and its improved results will be implemented in the upcoming simulation model to represent fluid interactions not only within each reservoir but also between different reservoirs that are produced in commingle. Firstly, a detailed quality check and validation were performed on every sample using a systematic process proposed in Paredes et al. (2014) to identify high-quality samples. These samples were ranked based on their Fluid Sample Quality index (FSQI), and the best samples were carried forward for further analysis. Initial PVT grouping analysis was performed by plotting observed saturation pressure, composition, CGR and other key variables versus depth for the selected samples. The existing PVT models and compositional characterization, which were reviewed and found to be satisfactory except for the matching quality of liquid saturation, were used to generate predicted profile trends using Compositional gradient experiments and compared to the data to define the PVT data that could be grouped together. Next, modelling and calibration of Equation of State (EOS) parameters to match the observed properties from lab experiments were performed for each PVT group using the best sample from each group as identified by its FQSI value. The results of the new PVT calibrations showed improvements over the existing models with the variance between the group PVT model and lab observations ranging from 0.1 -2.2% in saturation pressure and 0.5 – 17.8 % in CGR. This indicated that reasonable group PVT models had been obtained. Despite, uncertainty for one of the PVT groups remained high as its fluid needed to be adjusted due to a large inconsistency between the observed gas-oil-contact (GOC) and the observed saturation pressure even when its sample's FQSI was good. Finally, the new PVT models were validated with the existing dynamic simulation models by initializing them close to the original sampling conditions and applying a compositional gradient. Comparisons with previous models show improvements between 3 − 58% when compared to the sample and early production data. Significant uncertainty remains for the reservoir or PVT group where the fluid adjustment was performed due to its limited production for further calibration. In addition, improvements were not immediately reflected in the dynamic history match of the existing models because of the variation in separator conditions during field life and the uncertainty of wells’ zonal contributions from commingled production; these are aspects for future work.