Chemical Enhanced Oil Recovery (CEOR) has come into focus as a highly effective and versatile EOR method due to recent advances in the technology. However, CEOR particularly Alkali-Surfactant-Polymer (ASP) flooding is challenging in carbonate reservoirs. The main constraints are the undesired minerals such as calcite, dolomite, anhydrite and gypsum consisted of divalent ions. The minerals complex with injected chemicals and form precipitates that cause formation damage and scale formation in wells and surface facilities. This study presents a new Acid-Alkali-Surfactant-Polymer (AASP) flooding formulation as an alternative to conventional ASP flooding. AASP included acrylic acid as a precipitation inhibitor. The new formulation was compatible with the hard brine composition of 59,940 ppm TDS (with 2762 ppm divalent ions) for 30 days at 80 °C. AASP combination also provided acceptable interfacial tension and slug viscosity required for flooding in the presence of hard brine. Additionally, more than 30% Origional Oil in Place (OOIP) was recovered in the natural imbibition tests. Injecting 0.5PV of the optimum AASP formulation slug gave 18.9% OOIP to waterflooding in the coreflood tests. Thus, AASP flooding formulation is viable for suppressing the limitations of ASP flooding in carbonate reservoirs. Although, precipitation inhibitor increases the cost of chemical slug by adding several hundred parts per million (ppm) of inhibitor, significant cost savings will be realized because of the reductions in workover jobs and associated lost of production. Further, AASP flooding formulation also eliminates the need to soften the mixing brine. This will result in expanding the CEOR application to more challenging carbonate reservoirs and reduce the softening cost for mixing water. Introduction The term Chemical EOR is used in the petroleum industry literature to refer to a class of tertiary oil recovery. Chemical EOR is usually prefered after primary recovery (or natural depletion from expansion of reservoir fluids and reservoir compaction) and secondary waterflood recovery. Waterflooding is a process whereby water is injected into a reservoir to provide pressure support and to sweep oil to the production wells. In time, the oil produced as a percentage of total liquids production will decline. Eventually the oil cut will become uneconomical. At this point, the reservoir is considered to be at residual oil saturation to waterflood. The purpose of Chemical EOR is to recover the remaining or residual oil in a reservoir that has had its mobile oil swept and produced during a waterflood. To achieve this objective, oil needs to be contacted and mobilized. Oil can be contacted by improving the sweep efficiency of injected fluids. One way to do improve sweep efficiency is to increase the viscosity of the injected fluid relative to the connate fluids. This provides a more favourable mobility ratio, prevents viscous fingering, and helps to overcome reservoir heterogeneities (Manrique et al., 2010; Al-Mjeni et al., 2011; Manrique et al., 2006). Traditionally, sandstone reservoirs have been the most suitable candidate for chemical EOR applications. However, limited numbers of CEOR application are found in carbonate reservoirs throughout the last decades. The reason is high clay content which cause significant adsorption of surfactant and polymer. Dolomite, anhydrite and gypsum often occur in carbonate reservoirs. These minerals cause alkali consumption and formation of precipitates. Unlike sandstones which are homogeneous, carbonate reservoirs are generally complex in petrophysical characteristics. Therefore, chemical enhanced oil recovery is considered as, less effective in carbonate reservoirs (Manrique et al., 2006; Taber et al., 1997).
The paper discusses an innovative methodology of designing a carbonate reservoir model on a field in Central Luconia for planning further optimal field development and reservoir management & surveillance (RMS) using a Forward Stratigraphic Modelling (FSM) approach. Understanding of carbonate reservoir architecture is important for successful, stable hydrocarbon production and reservoir management plan. This understanding on early stages can help to prevent unpredictably low productivity & recovery, early water breakthrough and design field-customized RMS formulation. Complex depositional and diagenetic facies distributions in carbonate reservoir are the main challenges for development and production of hydrocarbon from carbonate fields worldwide. They are often naturally unique geologically, and exhibit complex porosity systems and permeability characteristics, which drastically influence whole cycle of reservoir management and surveillance. Geostatistical approach is often unable to capture the geological heterogeneity which leads to oversimplification of the carbonate reservoir model. Many uncertainties would be present in forecasted hydrocarbon and water production, volume in place and reserves estimation, optimal well design and locations, which effects the whole Field Development Strategy. This further becomes a challenging task in high mobility fluids like gas of Central Luconia with 90% of gas production in Central Luconia beingfrom Carbonate Reservoirs. With the complexity of the carbonate characteristics and its uncertainties, it is crucial for PETRONAS to reinvent its approach towards managing carbonate field and embrace the new ideas beyond those normal practices. By years of research and development of numerical computer simulations, FSM has proved to be a complementary alternative process-based approach to create a better carbonate reservoir model which is geologically realistic and obeys stratigraphic principles. The method used in the FSM approach is to first set the modelling input parameters which mostly represents the main depositional processes such as conditions of wave energy & direction, paleobathymetry, carbonate production rate, eustatic changes, amount of subsidence etc. These input parameters are obtained from an integrated approach of analysis on all hard data available including understanding of modern analogues to create a conceptual model at time of deposition. Once these input parameters have been identified, the simulation is computed to provide a first-pass model which is validated with hard data. If present mismatch, the input parameters will be tweaked and another simulation is computed. The steps are repeated until an acceptable match between the model results and the hard data is obtained. There will be numerous uncertainties available as many different input parameters may still provide different model results which matches the existing hard data available. Thus, a sensitivity and uncertainty analysis is computed to understand the most influential input parameters for creation of the reservoir model and also provide multiple model realizations which best represents the available hard data.FSM uncertainties are combined with G&G and dynamic uncertainties to have a robust model which can guide a formulation of optimal development and RMS planning.The innovative workflow applied at field scale allowed the modelling of highly heterogeneous, complex carbonate field which honours core, well logs, and seismic data.The application of this workflow honouring core, well logs, and seismic data as an alternative to conventional stochastic methodologies help to prevent field problems related to heterogeneity mis-modelling (simplification) in future such as unpredicted fast water breakthrough, reserves under/overestimation, field underperformance and help in the formulation and development of reservoir management strategies plan.
Material balance analysis, a primary engineering technique, is an indispensable tool used for understanding the production performance and field management of mature gas reservoirs. Compilation and analysis of pressure-production data together with acomprehensive geological understanding including in-place hydrocarbon volumes and inter-block communication are prerequisites for material balance analysis. Deviation of observed P/Z data away from a straight idealised line necessitates further study, as it often indicates erroneous estimates of participating in-place volumes, aquifer support or reserves. Lack of pressure measurements, questionable stratigraphic correlations and uncertainty surrounding aquifer propertiesor reservoir connectivity highlight the requirement for further evaluation. The objective of study is to develop a multi-tank material balance modelfor a mature, heterogeneous and compartmentalised carbonate gas field. Ultimately, the model must besufficiently robust to elucidate the field's production mechanism and optimise future field-development opportunities. In this field, the pressure production behavior can be divided into two trends, an early rapid declining pressure trend, followed by a stabilised gradual pressure decline. Owing to higher drawdown in the field's early production life and insufficient recharging, the quick pressure decline underestimates the initial in-place gas volume. This volume is not adequate to support the sustained gas production rates observed in later years. This observation required further detailed analysis regarding the nature of zonal communication across adjacent reservoir intervals to better understand the production behavior of development wells during the design of the material balance model. This paper discusses a study in which material balance analysis is coupled with multi-field network models. Implementation of this workflow can be usedto drive subsurface developmentsin a relatively short period.
Natural gas produced from underground reservoirs varies in its composition depending on the type, depth, and location of the underground deposit and the geology of the area. Natural gas is usually considered sour if the hydrogen sulphide (H2S) content exceed a certain threshold. And the term acid gas is usually used if it contains acidic gases e.g. carbon dioxide (CO2). Natural gas is called sweet gas when it is relatively free of H2S and CO2. The contaminants in natural gas needs to be treated or maintained within a certain limit as per the required pipeline quality for exports and sales. In Sarawak Gas Operations, the contaminants is being managed by means of integrated gas blending. Field B is one of the deepest platform-type carbonate gas reservoir in Central Luconia Province, offshore Sarawak with highest level of contaminants i.e. 40 mol% of CO2 and 2800 ppm of H2S. Sampling at more frequent interval of twice a year is implemented to monitor the trending of the contaminants level which will give perception on the effective blending management and maximum gas recovery. The strategy to produce as much as sour gas first while ample sweet gas is available to achieve maximum overall gas recovery is well understood. Observation on the trending for more than 10 years suggest that the level of contaminants is increasing by time and the field is souring. This finding is supported by the understanding of CO2 and H2S solubility in water which is higher as compared to hydrocarbon gases. The suspected mechanism for the reservoir souring is the changes in CO2 and H2S solubility in water with pressure change. This paper summarises the main issue of increasing contaminants level and effort to maximise gas recovery from the souring reservoir and discusses on the results from contaminants level trending and example from analogue field.
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