The gaint oilfield offshore Abu Dhabi was discovered in 1963 and came online in 1967. Horizontal drilling was introduced in 1989 to enhance recovery efficiency, leading to a large stock of horizontal wells to date. With the maturation and depletion of the field, areas of high, non-associated gas saturation have developed, and subsequent breakthrough to the horizontal production wells have resulted in high GOR that is above the shareholder's guideline. Many wells have been shut in due to high GOR. Controlling uneven production and early gas breakthrough are the main challenges to achieving target production and maximum hydrocarbon recovery. Inflow control devices (ICDs) create additional pressure drop to balance the production flux, but cannot restrict unwanted effluents ‘gas/water’ once they break through. The Autonomous Inflow Control Device (AICD) is an active flow control device that delivers a variable flow restriction in response to the properties (viscosity) of the fluid flowing through it. Gas flowing through the device is restricted more than oil. When used in an oil well segmented into multiple compartments, this design prevents excessive gas production when gas breakthrough occurs in one or more compartments. An evaluation of remedial advanced completion methods was conducted to select the best method of recompleting the shut-in wells and restoring oil production while controlling gas breakthrough. The solution must not only control gas production from zones of the well with high gas saturation now, but must be able to react to future increase in gas saturation in other zones as depletion continues. The "levitating disk" style AICD is ideally suited to this challenge, with the ability to greatly restrict the production from zones with high gas volume fractions. Modeling has indicated that total GOR can be reduced by 40% and total gas production reduced by over 60% compared to an open hole completion. This paper illustrates how AICD technology can enable operators to re-activate wells shut-in due to high GOR. This paper also describes a systematic approach for modelling flow in horizontal wells with AICD's, and presents an evaluation comparing different completion technologies used to control excessive gas production and maximize oil recovery.
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.
Majority of the oil and gas fields in the UAE are mature multi-layered carbonates reservoirs, which determines complex vertical heterogeneity and challenging development of those reservoirs. Conventional methodology to measure sublayer pressure is to utilizing different wireline formation testers for any new well or worked over well before commissioning for production. Once well is completed and put on production; usually the average reservoir pressure is measured at the depth of perforation using conventional pressure build up (PBU) or bottomhole closed-in pressure (BHCIP) methods. Using conventional approach it is always difficult to understand which layers are more depleted than others, as only average reservoir pressure is recorded in the wellbore. In case of the heterogeneous multi-layer reservoirs, pressure measured conventionally in the wellbore will be at most of the times, inadequate for sublayer pressure estimation. This paper will describe new methodology of formation pressure evaluation, as well as real case study done in one of the developed offshore carbonate field in the UAE. This method allows measuring each sublayer pressure for producing wells without interruption of the production and properly defining any differential pressure between sublayers. This will help when applying any gas shut-off or water shut-off techniques and prolong the life of producing wells, as well as to help future development of the field. The determined reservoir pressure for each layer has been compared with recent formation pressure tester measurements obtained for this well. The pressure measurement is in the range of 20 psi tolerance. Identification of sublayer reservoir pressure for each producing interval is vital for highly heterogeneous multi-layered reservoirs. This technique is important for gas and water production management when one or several sublayers become depleted. Appropriate action for gas/water shut-off technique can be applied in the right time which will help to manage reservoir efficiently, as well as reducing the cost for conventional pressure measurements and eliminating the loss of production due to shut in time for pressure stabilization during conventional BHCIP or PBU.
The formation pressure testing data is widely used in the oil & gas industry to understand the reservoir vertical heterogeneity and the fluid movement within the reservoir. With the recent advances in formation testing technology, now the subsurface engineers are able to visualize the rock and fluid characteristics beyond the conventional few centimeters into the formation without putting the well on production. A study for integrating all available formation pressure data was carried out in a field scale level. The holistic analysis of the data enabled the reservoir engineers to deduce critical information, such as, reservoir compartmentalization, reservoir depletion trend and the injectors’ efficiency. The aim of this paper is to demonstrate a novel approach of analyzing formation testing data on a field scale from a complex reservoir that enabled ADMA-OPCO subsurface team to make informed decisions for better reservoir management. Certainly, the replication of this analysis approach could benefit the petroleum community in the similar field development scenarios.
Water Injection is a part of secondary recovery to sustain Reservoir pressure and improve sweep efficiency and consequently improve recovery factor of the field with minimum cost. Source of the water is varying between offshore and onshore fields. Normally for all offshore fields, water injection source is sea water. However, it is vital to have proper water injection treatment system to avoid the risk of issues at surface and subsurface levels. This case study will show how water injection treatment system is important and their impact on the decrease of water injection efficiency due to plugging and corrosion. In addition, it will show the proper mitigation plan for improvement of water quality for short/mid and long term planning of the field development. Injected sea water should be treated mainly from the following parameters: –Sand solids from the sea using the sand filters–Oxygen removal from corrosion–Bacteria’s–Chemical inhibitors. Each of these parameters was checked and improved on the field and successful results were observed in terms of pipeline conditions and injection sustainability. Due to the poor water quality, every year 15-20 water injectors were plugged or decreased dramatically due to water quality. Improving the quality of the water and setting the proper guidelines for the treatment standards showed a positive impact on injection sustainability and consequently improved production offtake from the field. The holistic approach of the water injection treatment system and mitigation plan become possible uses the right standards of the treatment and correct surface facility. This will help to sustain water injection rate and decrease the number of acid jobs performed due to a decrease of the performance. Solving the cause of the problem is crucial instead of acting on the consequences.
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