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.

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 selection of optimum tubing size is one of the most critical steps in achieving the desired well productivity and prolonging the well life to maximize the hydrocarbon recovery; and it becomes more important for the naturally flowing well. It is a common industrial practice to reduce tubing size for extending the well life when a naturally flowing oil or gas well ceased to flow post experiencing the water breakthrough. Contrary to this general belief, an extensive piece of work has been carried to assess the well performance in high productivity (prolific) oil reservoir. In this paper, an actual case study is presented which demonstrates the overall better performance of a well completed with the bigger tubing size in a high productivity (prolific) oil reservoir. The study also compares the performance of the well completed in low productivity reservoir in the same field, which shows that the use of the bigger tubing size is a better option for sustaining the well life, hence negating the traditional industry belief of reducing the tubing size post water breakthrough into a well, regardless of the prevailing reservoir characteristics.

In order to meet the production targets set by ADMA-OPCO, more focus is given to inactive strings revival by undertaking quick and economical rigless intervention operations in carefully selected candidates. The candidate described in this case study is one of several old wells that are completed with 3 x 4 ½" tubing strings run side by side in a 12 ¼" borehole and then cemented in place. Some of the wells suffer high water cut causing one or more of the strings to cease production. The plan, after checking the integrity of the tubing, was to shut off the water zone and perforate a new zone using oriented perforating technology to avoid damaging the other 2 healthy strings. The well was completed in the past using an obsolete directional perforating technology. To shoot in the correct direction a special tool was used to orient the gun away from the other 2 strings before perforating. This tool has a shielded electromagnetic (EM) section that is sensitive to total metal thickness in the range of the measuring device. The gun and the measuring section are run into the well together on wireline and rotated by an electric motor until the gun is pointing in the correct direction. A joint task force between the ADMA-OPCO rigless intervention team and Schlumberger was created to assess the technology application and risks. Several simulations were done in a test jig built to simulate the well configuration both horizontally and vertically to assess the response of the tool. The ADMA-OPCO rigless intervention team was involved in the simulation, design and testing and have approved the operation after all the required tests were completed along with a risk assessment made to mitigate the expected risks. The job was executed successfully using the EM tool and zero phased 2-7/8″ hollow carrier guns, bringing an additional 3000 bbls of production. Confirmation that the job was successful was made by putting electronic gauges in the other two strings to record a communication test done before and after perforation. This is the first time this technique has been used in the Gulf and it has strong potential in similar environments in the area.

The paper discusses the pilot project in ADNOC Offshore to assess the Autonomous Inflow Control Device (AICD) technology as an effective solution for increasing oil production over the life of the field. High rate of water and gas production in horizontal wells is one of the key problems from the commencement of operation due to the high cost of produced water and gas treatment including several other factors. Early Gas breakthrough in wells can result in shut-in to conserve reservoir energy and to meet the set GOR guidelines. The pilot well was shut-in due to high GOR resulted from the gas breakthrough. A pilot project was implemented to evaluate the ability of autonomous inflow control technology to manage gas break through early in the life of the well spanned across horizontal wellbore. And also to balance the production influx profile across the entire lateral length and to compensate for the permeability variation and therefore the productivity of each zone. Each compartment in the pilot well was equipped with AICD Screens and Swell-able Packers across horizontal open hole wellbore to evaluate oil production and defer gas breakthrough. Some AICDs were equipped with treatment valve for the compartments that needed acid simulation to enhance the effectiveness of the zone. The selection factors for installing number of production valves in the pilot well per each AICD was based on reservoir and field data. Pre-modeling of the horizontal wellbore section with AICD was performed using commercial simulation software (NETool). After the first pilot was completed, a detailed technical analysis was conducted and based on the early production results from the pilot well showed that AICD completions effectively managed gas production by delaying the gas break through and restricting gas inflow from the reservoir with significant GOR reduction ±40% compared to baseline production performance data from the open hole without AICD thus increasing oil production. The pilot well performed positively to the AICD completion allowing to produce healthy oil and meeting the guidelines. The early production results are in line with NETool simulation modelling, thereby increasing assurance in the methods employed in designing the AICD completion for the well and candidate selection. This paper discusses the successful AICD completion installation and production operation in pilot well in ADNOC Offshore to manage GOR and produced the well with healthy oil under the set guidelines. This will enable to re-activate wells shut-in due to GOR constraint to help meeting the sustainable field production target.