As part of the feasibility assessment for an improved oil recovery project on the Sahil reservoir in the United Arab Emirates, it was desired to assess the potential for asphaltene formation arising from the miscible contact of a rich hydrocarbon injection gas and the Sahil reservoir fluid. In this work, experimental data for the upper and lower asphaltene onset conditions over a temperature range from 110– 255°F were measured for the reservoir fluid. In addition, three injection gas mixtures (15, 45, & 60 mole%) were also evaluated at the reservoir temperature of 255°F. The experimental data were measured using a Near Infrared (NIR) light scattering technique. Subsequently, the experimental data was used to tune an equationof- state (EOS) based model that represents the asphaltene phase as pseudo pure component solid. Results of the work demonstrated a significant effect of temperature and injection gas concentration on the asphaltene onset conditions for the reservoir fluid. It was also shown that the chosen model could accurately represent the measured behavior of the fluids over the range of conditions tested. Introduction The Sahil reservoir in the United Arab Emirates, was first brought on to production in 1973 and has been produced under primary depletion up to 1994. The reservoir performance indicated that there was no aquifer support. Hence, a pressure maintenance scheme in the form of peripheral water injection was implemented in 1994. Subsequently, a miscible rich gas injection trial was initiated in 1998 with four gas injection pilots, one gas injection pilot to the North of the field and three pilots in the central part of the field. Solids depositions were observed in many producing wells. A summary of the Sahil reservoir fluid properties is provided in Table 1. These properties confirm a typical black-oil reservoir fluid. Properties of note for the stock tank oil include a n-C5 insoluble asphaltene content of 1.3% (w/w), a wax content of 7.9% (w/w) (UOP 46–64) and a corresponding cloud point of 140°F (ASTM D-2500). These values are reasonably typical and would generally not indicate a great risk for wax or asphaltene formation under primary production. Generally, asphaltenes tend to remain in solution or in colloidal suspension under reservoir temperature and pressure conditions. They may start to precipitate once the stability of the colloidal suspension is destabilized, which is caused by the changes in temperature and/or pressure during primary depletion.1 On the other hand, asphaltene have been reported to become unstable as a result of fluid blending (co-mingling) of fluid streams2 as well as by gas injection during Improved Oil Recovery (IOR) operations.3–6 Due to these observations, and in view of the consideration of gas miscible IOR operations on the Sahil reservoir, it was felt that an assessment of the asphaltene formation potential for this reservoir may be advisable. For this reason, a work scope including experimental measurements and theoretical modeling was initiated. This work outlines the results of that effort.
This paper was prepared for presentation at the 8th Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, U.A.E., 11-14 October 1998.
In tight carbonate reservoirs, several factors make it difficult to estimate reserves in transition zones. In particular, underestimation of reserves sometimes occurs because the formation oil can be more mobile than expected. The measurement of mobility of the different phases throughout the transition zone, which is affected significantly by complex rock heterogeneity, can only be accomplished by selective flow measurements. To use openhole sampling tools for these flow measurements, it is essential to differentiate between water-base mud (WBM) filtrate and connate water thereby avoiding any negative impact on the oil initially in place (OIIP) calculation and on development decisions. In principle, pressure gradients from traditional open-hole point pressure measurements should help define accurate fluid gradients and contacts. However this procedure is inadequate to identify and characterize the transition zones. Supercharging, capillary effects, changing wettability and saturations, and pressure variations from production and/or injection effects all play a role in complicating interpretation of the pressure measurement data. In addition, gauge effects, depth errors, formation thicknesses and fluid density contrasts yield potentially large uncertainties in interpretation of gradient data. Downhole pH measurement, embodied within Downhole Fluid Analysis (DFA) procedure, has dramatically improved the situation. Downhole pH measurements utilizing robust pH dyes, the principle behind Litmus paper, have been successfully utilized in differentiating between WBM filtrate and formation water. The downhole fluid analyzers LFA* and CFA* successfully helped determine the level of the anticipated water cut, oil compositions and gravity, and GOR throughout the transition zone allowing a more reliable estimation of hydrocarbon in place and better well placement and production strategies. This process yields considerable cost savings especially by avoiding expensive production tests. Introduction Worldwide, carbonate oil-water transition zones contain vast quantities of economically producible oil. In the literature, numerous studies have been published on the potential and importance of capillary transition zones [1–8]. In particular, several large, low permeability carbonate oil reservoirs have transition zones on order 50 meters in height. Considering that some of these fields have been produced for decades, much (up to half) of the remaining oil is in the transition zone. Consequently, it is a necessity to understand what fluids will be produced if the transition zone is swept or if there is movement of the OW contact. In addition, some authors [2–7] have explained the importance of changing wettability; the transition zones are often increasingly oil wet towards the top. It has been reported that a reduction in oil wetness is accompanied by a reduction in irreducible oil saturation (under primary imbibition), and a commensurate increase in the relative permeability of the oil. But, when one drills a well with Water-Base Mud (WBM) through a transition zone, how does one quantify the mobile oil saturation and the associated relative permeability? Assuming a typical scenario in which decisions about where or even whether to drill a production well, need to be rapidly made, an efficient, reliable method of diagnosing the transition zone is desirable. However, the formations are often of mixed and variable wettability. It has observed that the saturation exponent of the famous resistivity-based Archie equation depends on the initial oil saturation and varies across the capillary transition zone for mixed-wet and oil-wet reservoirs. Furthermore, in carbonate systems, the interplay of primary and secondary porosity introduces significant complexity. Path-of-least-resistance effects can be present in carbonates due to the complex and heterogeneous pore structures, which often makes that the water saturation of the formation across oil-water transition zone difficult to interpret in terms of true resistivity.
Reservoir management practices are classically based on analytical models and standard Reservoir Engineering tools. In the waterfood or water alternating gas recovery process, the analysis is made traditionally with the hypothesis of constant predefined patterns. The producer – injector pair's interaction is quantified based on predefined geometrical analysis of the percentages of contribution of each injector to a producer. In the absence of certain degree of reservoir homogeneity, and also possible injection/production technical issues this method presents a lot of limitation and may lead to erroneous results. Fields in the Middle East are dominantly carbonates and the flow paths are guided by heterogeneous distribution of reservoir characteristics mainly permeability. This paper outlines a case study for the usage of streamline simulation in predefining the optimized rates of each producer and injector in order to optimize the recovery from individual pattern. The study quantified the interaction between producers and injectors pairs and defined the dynamic pattern distribution through the history. A number of attributes can be derived for each producer injector and pattern. Attributes such as the instantaneous and cumulative voidage replacement ratio, sweep efficiency and injection leakage can be analyzed in order to give more weight in the optimization stage to certain producer and certain injectors. It was concluded that the geometrical lay out of the patterns is not necessary respected and the injectors may support producers outside their geometrical patterns. There was as well a certain amount of the injection that is not contributing to any production and it is not targeting or supporting any specific well. A number of forecast scenarios were conducted and through ranking different realizations based on total patterns sweep efficiency, the best scenario was selected to determine the allowable volumes to be injected and produced. The scenario showed better control of the patterns as there was a reduction of any redundant injection and the leakage was cut down.
This paper presents a case study of developing a significant volume of oil rim with a large gas cap reservoir in Abu Dhabi-UAE. The reservoir is a low relief heterogeneous carbonate located in a complex environment represented by natural and artificial islands in the surface, shallow and medium water marine areas. The reservoir rock properties showed lateral and vertical heterogeneities as well as variation in reservoir fluid properties. The static and dynamic data were utilized to construct representative geological and dynamic models for the reservoir. The field development objective focused on producing the oil rim while maintaining the gas cap as long as possible to save the reservoir energy and benefit from the gas cap pressure support. Five years production dynamic data were available from two oil producers in addition to well testing and MDT data during the appraisal phase "13 wells". These data were used to quality control the initialization and history match phases. The development options included pressure support using water injection, lean gas injection, miscible gas injection and miscible WAG injection. The predicted reservoir performance of the oil rim indicated considerable gas cusping from the gas cap in all the development options. It was a challenge to reduce the amount of gas production from the gas cap in all the development options. A new development option was introduced to perform miscible gas / WAG injection underneath the gas cap accompanied with optimization of the wells and completion intervals locations for producers and injectors to minimize the gas cusping from the gas cap. This resulted in significant enhancement of minimizing gas cusping with minor impact of the recovery factor. The development of the oil rim was suggested to be in phases focusing on the lowest uncertainty segment of the reservoir. This paper provides the methodology followed to guide the development plan to fill in the uncertainty gap by a detailed data acquisition and monitoring programs to better understand the reservoir behavior.
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