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Challenges associated in developing mature offshore fields of Saudi Arabia require the optimal integration of best reservoir management practices. Such complicated fields require effective collaboration between reservoir engineers and geoscientists for the application of latest technologies and best practices. A variety of practices were implemented to achieve significant improvements in drilling and completing horizontal wells. Some of these challenges have been addressed with the installation of over 200 inflow control devices (ICD) which are used to minimize water coning and gas cusping affects. Economic development of these offshore projects have involved the implementation of 20 Smart wells, in conjunction with, intelligent field monitoring that improves surveillance and reduces manpower requirements. Real-time geo-steering practices, advanced logging measurements, and seismic imaging techniques were successfully utilized for well placement of over 100 horizontal wells in a geologically complex sandstone environment. Also discussed are some future fit-for-purpose technologies that are being considered for these offshore field development projects. Introduction The developed offshore fields (M, Z and S) of Saudi Arabia are located in the Arabian Gulf and consist of sandstones, siltstones and shales with minor limestones and coals deposited in a complex, fluvial dominated delta system. The main producing reservoirs consist of massive, clean highly permeable 1-5 Darcy sandstone units interspersed with shales. The primary drive mechanisms for all three fields results from natural aquifer influx with limited support from gas cap expansion in two fields. Table-1 shows some reservoir characteristics and completion type. Historically, all wells drilled in these fields have been free flowed to the surface without any artificial lift. Recently, one of the fields installed a number of electrical submersible pumps (ESPs) to increase well productivity. For other wells that cease to flow at high water cut, a drilling program has been undertaken to convert these vertical wells to horizontal wells with passive inflow control devices (ICDs). Horizontal wells were introduced in the early nineties in all Saudi Arabian offshore fields to sustain production targets. Before 2003, most horizontal wells drilled in the sandstone offshore reservoirs were completed as cemented and perforated liners completions. After 2003, many of the new horizontal wells began using ICDs to improve production profile along the horizontal lateral section. These new completions increase the distance to the oil water contact (OWC), reduce water coning tendencies, and extend the life of the well. Additionally, for those those wells located in fields with a central gas cap dome area, Smart in-situ gas lift technology is available to increase production and further extend well life. The objective of this paper is to share the best reservoir management practices and strategies to meet challenges associated in developing mature offshore fields of Saudi Arabia.

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Cores, open hole logs, formation testers, pressure transient tests, and production logs are usually used to assess reservoir heterogeneity. A common limitation of these techniques is that they do not provide two-dimensional spatial information of reservoir characteristics. For example, cores and logs have excellent vertical resolutions, but very small lateral radii of investigation, and the pressure transient tests have a large lateral radius of investigation, but very poor vertical resolution. Constructing an appropriate simulation model requires rescaling the data, and that may introduce significant uncertainties. To address these limitations, we explored the use of electrode resistivity array (ERA) measurements in a carbonate formation for reservoir characterization. The ERA was installed on tubing in a barefoot well rather than permanently cemented outside the casing as in previous applications. This notable difference introduced particular issues in the ERA data acquisition and interpretation, but also provided flexibility for device installation and operation. Furthermore, the ERA measurements were carried out in conjunction with low-salinity water injection and production in the same well. It was found that the ERA voltages near a source electrode showed unique characteristics that represented local formation heterogeneity. Although the new technology can be used at any scale, the focus was on characterizing formation heterogeneity within the length of the ERA string in the vertical direction and about 100 ft laterally around the wellbore. The scale of the investigated formation heterogeneity is comparable to grid sizes used in current reservoir simulations. Models were developed to identify stratified permeability heterogeneities from the time-lapse ERA voltages. The stratified heterogeneity estimated from the ERA measurements was compared to and verified by open hole logs and core analyses. The final heterogeneous reservoir model from ERA was subsequently applied to a numerical simulation that integrated the dynamic fluid flow, salt transport, and electrode array responses for water front monitoring and multiphase formation property evaluation and confirmed the first pass estimates of the identified heterogeneities. Introduction Permeability heterogeneity, especially that induced by formation stratification, is very important in all aspects of reservoir engineering processes, from well placement to enhanced oil recovery applications. The stratified and interwell heterogeneities dictate fluid movement and waterflooding efficiency, thus significantly affecting hydrocarbon recovery. This is particularly true in carbonates, for which reservoir heterogeneity exists at many different scales. Detailed reservoir characterization is needed to better map the formation heterogeneity for reservoir management. Core experiment, open hole wireline logging, wireline formation tester, pressure build up, injection/fall off test, and production logging are the conventional methods for characterization of reservoir heterogeneity. Although applications and advantages of these techniques in formation evaluation are well established, each has limitations that should not be overlooked. In general, these measurements can be divided into two categories: static and dynamic.

In this paper, we present a novel method for in situ estimation of two-phase transport properties of porous media using time-lapse resistivity, pressure, and flow rate data from a permanent downhole Electrode Resistivity Array (ERA) and pressure, and a production logging tool. The primary objective of this Fluid Movement Monitoring (FMM) setup and experiment is to provide in-situ measurements required to determine multiphase flow properties, such as relative permeabilities and capillary pressures. Continuous monitoring of oil displacement by injected water in all the permeable zones was conducted in a carbonate reservoir in Saudi Arabia. The field experiment was divided into two stages:Selection of the well location, coring and logging, experimental setup and completion designs, cleanup, production profiles, pressure transient buildup tests, water injection and subsequent production of all injected water, and collection of all relevant data that include time-lapse pressure, production and injection profiles, and resistivity; andInterpretation of all the data acquired from different sources, development of algorithms/software to compute the movement of the injected fluid through the reservoir, and the inversion of multi-source and multi-physics measurements. This monitoring experiment was achieved through an integrated interpretation of different data sets such as transient drawdown/injection and drawdown/buildup tests, 3D deep resistivity, production and injection profiles, openhole log, and core measurements. This approach is new to the industry and the first field experiment for direct in situ determination of two-phase flow properties. The key outcome of this field experiment is a full verification of the permanent downhole resistivity array and pressure sensor experimental setup for estimating in-situ layer relative permeabilities and capillary pressure and monitoring water movement inside the formation. This allowed multiphase characterization of the formation around the measurement well to a radial depth of tens of meters.