Rock typing is one of the most important steps in reservoir modeling, and it’s the main task in reservoir characterization. In carbonate, the rock typing work that’s been performed during the last two decades had a little progress in term of providing reliable estimation of reservoir behavior. However, the development of Conjunction Rock Properties Convergence, CROPC, a carbonate rock typing concept that provided an important and easy solution to the carbonate rock typing gaps, has a major breakthrough, even though, CROPC methodology was developed to capture the single pore network through the conjunction of Lithology, permeability, capillary pressure and water saturation. Therefore, the need to identify more complex carbonate pore network had led to the initiation of developing the Carbonate Rock Type Matrix RocMat, which will be detailed in this paper, as part of a Master of Science research project. In this novel concept the carbonate rocks were classified into homogeneous, single pore network, and heterogeneous rocks, dual and triple pore network with the utilization of the effective petrophysical properties of permeability, capillary pressure, saturation, porosity and height above free water level, all were classified in a conjunction matrix that honors these properties and at the same time enables generating sub groups as down scaling and estimation for unseen groups with infinite rock complexity capturing, at the same time it enables the ease to lump the groups and generates upscale-groups that make it easier for utilization by the geologist and reservoir engineers to achieve the objective of better reservoir performance prediction, the work was performed and then tested in two carbonate offshore fields data. This RocMat was structured to be the ultimate catalog for carbonate rock types.

The main objective of this study is to enhance a Predicted Permeability (K_Pred) by integrating Permeability resulted from the interpretation of more than 100 P.T.A. Initially the predicted permeability was generated using neural network method (Combining core and log data) over all 254 wells penetrating the reservoir. To achieve this task a number of workflows have been discussed and tested and finally two methods were implemented which resulted in two permeability models. The first model, consist of generating enhanced permeability maps for each porous zone using Permeability Predicted (K_pred), core and well test data. These maps were used as multiplier in Upscaled model to generate the total permeability then exported to reservoir engineer for simulation. The second model, consist of generating the enhanced permeability by integrating Permeability Predicted (K_pred), core and well test (KH) under each well (Log scale) in order to capture the dynamic changes of the property. This enhanced permeability was populated in geological model using stochastic methods conditioned to Rock Type and porosity.

Reservoir characterization is the most important input element in building a robust geological and simulation models. The Improvement in reservoir description enhances the understanding of the reservoir heterogeneity and reduces the uncertainties on field development. This can be achieved with better characterisation of reservoir properties such as Rock Types, porosity, permeability and saturation. The reservoir is developed by water and gas injection. In order to better understand field behavior, enhance oil recovery, produce difficult oil, a detailed reservoir characterization study was performed, followed by construction of fine grid geological model and simulation model. The main goal of the model is to predict middle and long term development plan. The depositional model represents a shallow water carbonate platform with a set of facies that characterize each system tract. These facies range from bioclastic Wackestone, Mudstones, with sponge Spicules of shallow shelf through a shoal area with Peloidal and Oolitic grain dominated fabrics to the restricted lagoon foraminifera bioturbated Wackestone and microcrystalline dolomite and finally into the upper intertidal facies of macro crystalline dolomite and nodular anhydrite. The digenetic model comprised surface, subtidal, shallow, and deep burial diagenetic events, such as micritization, fringing calcite marine cement, vadose grain leaching, compaction, stylolitization, dolomitisation, anhydrite cementation and fracturing.

The aim of this paper is to share a successful case study of implementing the GLDA acid in two case study wells, which helped in improving the well performance where conventional HCl acid was not effective. Historically, the conventional HCl acid stimulation was performed on two case study wells, however, little to no improvement was observed after the acid job. The production history of both wells showed unstable behavior with load up tendency against the system pressure. Both wells frequently require unloading operation to put the well back online in case of any unforeseen platform shut down. In order to enhance the well performance and to sustain the productivity of the wells, an alternative acid called GLDA (Glutamic Diacetic Acid) stimulation was considered. GLDA is an environmentally friendly acid, biodegradable under water, non hazardous and can be handled and transported without special safety precautions. Unlike conventional HCl acid stimulation, GLDA acid is more expensive hence; a comprehensive process was adopted to ensure the proper candidate selection. For compatability study, the core samples from multiple reservoirs were tested with GLDA acid which showed positive results (creating deeper worm holes in all the cores provided), especially in the low permeable reservoirs. Fluid compatibility test of GLDA with crude oil was also found suitable without any asphaltenes precipitation & emulsion. Stimulation with GLDA acid was applied on both wells. Post job results proved significant enhancement in the production as well as production sustainability versus the conventional HCl acid stimulation.

The current practice of stimulating thin layered carbonate reservoir using conventional acid stimulation techniques (CT stimulation or Bull-heading with CDC) have proven to be ineffective and inefficient as acid tends to propagate more in the higher permeable streaks than low permeable ones. The new approach aims at addressing this problem by increasing the contact surface in the lower permeable streaks to improve its productivity using expanding metal needles. The vendor has developed a new method for acid stimulation of carbonate reservoirs. The system is encompassed in self-contained subs which are integrated in the open-hole liner and placed opposite to zones of interest. Acid is bullheaded and a large number of small diameter tubes (needles) jet out simultaneously from the wellbore to penetrate the reservoir, creating numerous flow tunnels. The major application for this technology is to enhance well productivity by connecting the wellbore to the body of the reservoir with as many as 300 flow tunnels. These tunnels drain increase the surface area of the low permeability reservoir layers exposed to flow and hence increase well productivity and reserve recovery. After completing the stimulation job, a special tool is run to clear the open-hole liner from the metal tubes and keep production ports open to allow accessibility to reservoir for injection or production as well as running of production logging tools for reservoir monitoring. The new system (4-1/2″) was successfully installed in one well but cleaning of open-hole liner failed due to design problem related to the cleaning tool. Several meetings with vendors have resulted in a wealth of lessons learned on how to improve the system for future application. As such the well is capable to flow but accessibility for intervention is limited. The initial unloading of the well showed encouraging results from the Fishbone stimulation however later the analysis of flow test monitoring with bottom hole pressure showed decrease in productivity by 35% within short diction of time (~ 2 months). This type of performance has not been seen in other open hole horizontal wells in the field. Also the GOR of the well has increasing trend from the beginning of the production, possibly due to developed communication with top high GOR layer.