The challenge in the development of gas condensate reservoirs is to recover the most valuable hydrocarbon component, "condensate". Pressure drops below the dewpoint anywhere in the reservoir cause condensate dropout. When the pressure drops near the producing wells, condensate banking can occur, which impedes production. Gas recycling is one of the efficient ways of developing such reservoirs because it maintains reservoir pressure and hence increases the condensate recovery. Demand for gas has resulted in a strategy of nonhydrocarbon (NHC) injection in selected areas of the field. An NHC method under study has the potential to raise the dewpoint of the reservoir fluid making it more susceptible to condensate dropout. The objective of this study was to quantify the effect of NHC injection on recovery of condensate and hydrocarbon gas and the effect on productivity of wells. In this study, sector models are extracted from a full field model. The molar recovery of hydrocarbon component and condensate recovery were analyzed under the effect of reservoir properties and distance between wells and injection stream. NHC breakthrough time and tracer modeling were also studied. The NHC under study was found to be inefficient compared to the hydrocarbon injection in all cases; however, the properties of the rock and distance between wells impact the efficiency. The difference in recovery factor at two pore-volume injection with NHC injection was nearly 5% less than that with hydrocarbon injection at pressure 4,700 psi, and this difference increased to 10% at 3,000 psi. NHC is poor in revaporizing the condensate dropped in the reservoir whereas hydrocarbon gas can efficiently revaporize condensate either by first-contact miscibility or by a multicontact miscible process.

Gas injection is a recognized enhanced recovery technique for oil reservoirs, but has been given less attention for gas condensate fields. If a gas condensate is produced by natural depletion, the condensate-gas ratio of the produced well stream will steadily decrease after the saturation pressure is reached. The liquid condensed will stay back in the reservoir and will not be produced. A laboratory study was conducted for a Middle East gas condensate reservoir fluid. Three different injection gases were used- N2, CO2 and a lean hydrocarbon gas. A gas revaporization experiment was conducted with each gas on the depleted reservoir fluid. The gas revaporization experiments showed that injection of CO2 made the liquid dropout in the PVT cell decrease substantially. Already condensed liquid was revaporized and led to an increased liquid content in the released gas. In small concentrations N2 made the liquid dropout increase, but with a continued injection of N2 the amount of liquid dropout declined. The hydrocarbon gas made the liquid dropout decrease at all concentrations, but to a lesser extent than CO2. An analysis of the results showed that injection of CO2 and a lean hydrocarbon gas may substantially increase the liquid recovery from the actual field, while it is questionable whether N2 injection will have much impact on the liquid recovery.

A giant lean gas reservoir overlying a large oil rim is producing for more than 27 years became under depletion mode without any pressure maintenance. Formation collapse in reservoirs under depletion can cause permeability reduction, completion damage and well failure, reducing or even interrupting production and affecting the ultimate recovery from the reservoir. It is therefore critical to predict any risk in formation collapse. If such risks exist, recommendations are required to optimize reservoir management. Stress measurements were acquired and core analysis were performed in intact rocks area and used for 1D MEM (Mechanical Earth Model) and 3D MEM. 1D MEMs for 10 wells were constructed. Rock mechanical tests were conducted on core samples. 3D MEM was created with 13 interpreted seismic overburden horizons and 105 seismic faults. Four scenarios were performed to identify formation failure during the scheduled production. The worst-case scenario will happen of reservoir depletion, in case of weak formation and reactivated faults. Intensive logging, fracture modelling, coring program across the main fault corridor and RMT (Rock Mechanics Tests) were performed in vertical and horizontal holes across the fault corridor area to fulfil gaps of rock mechanical properties (elastic properties and rock strength) and field stresses. The acquired data were seeds for Lab testing, fracture network analysis and fault characterization which used to update the 3D MEM. Additional Lab tests to fill gaps in rock samples with high porosity (> 30%) were carried out and 1D MEM of 5 more wells were constructed, and the 3D MEM were updated. The 2017 updated 3D MEM eliminates three of the 2013 four scenarios and ended up with one robust scenario that shows better reservoir integrity and very small localized areas of pore collapse in high porosity regions only (> 30%) compare to the previous model. The reservoir can produce under depletion mode with production optimization in areas of expected compaction. Well integrity study and compaction monitoring are also considered to be commentary studies.

The presence of Low Resistivity Pay (LRP) in reservoirs has been widely reported worldwide for both, clastic and calcareous formations. By definition, a LRP is not identified by the resistivity log, as its electrical beam is short circuited by the microporosity water bearing. This effect results in lower responses than expected for the conventional resistivity log, and hence, in higher estimations of water saturation that observed from production data. There are many factors that could create a LRP effect such as water invasion, conductive minerals, fracturing, thin bedding, fresh formation water or rock fabric (i.e. microporosity). Regarding to rock fabric as driver for the LRP effect, the most common is the presence of the microporosity. This microporosity can be created by diagenetical processes (i.e. micritization) or whatever other component or process which preserves a microporous system inside the total porosity system of the rock. The presence of microporosity in the porous system, as a water bearing system, acts as an electrical shortcut for the electrical current, and it increases the general water content as calculated by the resistivity tool. The result is that SW due to microporosity contributes as Irreducible Water Saturation (SWirr) and not as Free Water Saturation (SW), with a direct effect on reserves assessment (Static Model), but with no significant effect to the field production (Dynamic Model). The aim of this study is to identify the eventual presence of a LRP, and to determine its origin. By the above, a new fluid saturation assessment was performed based on both, available core and log data, together with a new set of core data focused on the available cored oil wells, in order to identify and recalculate the Gas, Oil and Water saturations for building a the new Static and Dynamic models. The new set of core analysis includes not only Conventional Core Analysis (CCAL), such as air porosity, grain density, Ka, Kk, Kg, CT Scanning or thin sections, but also Special Core Analysis (SCAL) as Mercury Injection Capillary Pressures (MICP) and Nuclear Magnetic Resonance (NMR).

An Offshore Gas Field discovered in early 70' is a large anticlinal structure located in the shallow marine waters west of Abu Dhabi island. The area is considered by UNESCO as Biosphere reserve and is protected. Several development options have been studied to develop the gas reserves from existing Artificial Island with a minimum impact to the environment.Geological and reservoir simulation compositional models have been prepared to optimize the development plan, identify the minimum number of wells, target rates in order to maximize the gas recovery and sustain the gas plateau rate as long as possible. Building these models was a challenge due to the lack of 3D seismic data and the limited production data from the appraisal well. Due to the sensitivity of the area, the main challenges of the project implementation are the impact on the environment during drilling phase and the facilities construction and its operation.The required refurbishment of the existing island and access channel to the island was a concern that was studied. Drilling of 10 to 12 closely clustered directional deviated gas wells from one existing artificial island in the centre of the field into a High Pressure and High Temperature, high H2S (14-24%) and deep reservoirs environment is also a big challenge. To effectively drain the entire reservoir from the island, the rigs should be capable to drill more than 25,000 ft extended reach deviated wells.Reducing the impact on this sensitive environment was the major concern; hence an HSEA study has been carried out to develop the mitigation plans. The possibility of drilling using more than one rig simultaneously on the island to deliver gas on time has been studied to minimize the duration of the drilling operation and associated risks. Special completion materials for these extreme environments were also studied. Material selection for different well types/conditions has been carried out.