Raageshwari gas field is a relatively deep (3000m) non-conventional volcanic reservoir with a gas column in excess of 800 meters. Gas from Raageshwari field is used to generate energy for production of waxy high pour point crude of the nearby Mangala, Bhagyam and Aishwariya Fields (which were discovered in January 2004) in Barmer Basin, Western Rajasthan India (Figure 1, 2). Extensive laboratory studies have been conducted prior the hydraulic fracturing treatments to evaluate rock mechanical properties, rock -frac fluid interaction and mineralogy. MiniFrac analysis was performed prior to the main frac treatment in order to have a better understanding of the reservoir properties prior to pumping of the main hydraulic fracturing treatment. Microseismic fracture mapping was used to determine fracture geometry and azimuth. Fracture modeling was also used to determine effective fracture geometry which was later calibrated to the Microseismic data. Different techniques have been successfully utilized to overcome extreme fracture complexity and resultant screen-outs including proppant slugs, 100 mesh and high viscosity slugs.

The Raageshwari Deep Gas (RDG) Field in the Barmer Basin, India is a lean gas condensate reservoir, with excellent gas quality of ~80% methane, low CO2 and no H2S. The productive zones are in volcanic rocks and volcanogenic sediments. From a permeability perspective, the RDG reservoir is similar to typical tight gas reservoirs in other parts of the world which cannot be commercially developed without large-scale hydraulic fracturing. Recent RDG hydraulic fracture treatments have been monitored with microseismic mapping technology. The microseismic data was acquired in June 2010 to quantify the trend of hydraulic fracture networks induced in a 5-stage stimulation program. The recorded P and S wave events were subsequently mapped in 3D space by fracture stage (in time) to effectively represent the onset, propagation and trends of the fractures and the extent, overlap or inter-connection of the resulting fracture networks. The initial objective of conducting microseismic mapping was only to calibrate the existing fracture simulator. Earlier hydraulic fracture treatments had been conducted with a conventional gas condensate frac design in mind, with targets of ~100m of frac length and a dimensionless fracture conductivity (FCD) ranging from 5-10. The initial frac schedules were designed with large pad and proppant stage volumes (~275,000lb of 20/40 ISP and 16/30 ISP). The efficacy of these fracture treatment designs was to be verified with the microseismic mapping technology. It was found that RDG does not have the typical tight gas reservoir architecture which was assumed for the initial frac designs, but consists of tight matrix porosity contained within a very complex network of natural fractures and planes of weakness with conjugate jointing. Hence the conventional fracture design was changed to deal with such fracture network for future fracturing campaigns.

The Raageshwari gas field is a relatively deep (3000m) unconventional volcanic reservoir with a gas column in excess of 800 m. Gas from the Raageshwari field is used to generate energy for production of waxy, high-pour-point crude in the nearby Mangala, Bhagyam and Aishwariya fields (which were discovered in January 2004) in Barmer basin, Western Rajasthan, India (Figures 1, 2). The gas reservoir has inherently low permeability, and hydro-fracturing treatment is essential for optimum production from the field. A series of hydro-fracturing operations have been carried out on the field and treatments optimized over a period of time. A recent fracturing campaign implemented a shift in perforation methodology from conventional e-line perforation to peroration using sand jetting through coiled tubing. This paper discusses the challenges that had been associated with hydro-fracturing work in the field and benefits achieved with sand-jet perforation technology.

This paper describes a game-changing solution regarding the use of metal expandable annular sealing systems in a high pressure multistage frac well. The design and engineering of this technology resulted in the development of fit-for-purpose equipment that overcame challenges often encountered in a high-pressure stimulation environment. The metal expandable annular sealing system was custom designed in order to provide high expansion that can be set in potentially washed out wellbores. The design included a long multi-element sealing system with built-in redundancy to account for fracturing fluid chemical reaction with the rock behind the seals. The system is just under 4 meters, complemented with multi-elastomer seals, each delivering full Delta P capability within a washed-out hole up to 6.5". The unique design allows full rotational capabilities during deployment, minimizing operational risks. The system was run in combination with multi open-close fracturing sleeves and a pressure activated toe sub rated to 10,000 psi for acid fracturing in three zones of a vertical carbonate well – the well was known for its heterogeneity and high reservoir pressure contrast. The use of mechanical packers with short sealing elements would have been challenging and increases the risk of unwanted communication between zones. Successful installations, activation of the sleeves and subsequent hydraulic fracturing were achieved, which enabled operational flexibility, reliable isolation and high expansion benefits. Acid fracturing treatment data from each of the stages were analyzed and used to confirm that the zonal isolation integrity. This paper includes the challenges of providing zonal isolation with conventional packer designs and details the design, testing and qualification of the solution as well as further design modifications for higher fracturing pressure rating.

This paper discusses the first successful in-Kingdom coiled tubing intervention in a well without conventional stripping-out of the well leading to significant cost savings, reduced risks, and compliance to Saudi Aramco environmental protection policies by adhering to a zero flaring initiative. Conventionally, wells are shut-in, secured, and stripped out (depending on the operation, stripped out refers to the disassembly and removal of directly connected piping, cathodic protection, and other production system components) in preparation for performing any high pressure coiled tubing (HPCT) interventions (to allow crane and HPCT units to spot and rig-up). Wells are then again re-manifolded to the production system. These stages consume a tremendous amount of manpower, cost, time, and production loss. Unfortunately, some wells have severe condensate loading issues, to the extent that they tend to die again, during shutdown (re-manifolding period) after the lifting operation. A new approach was required to be developed to avoid asset depletion in problematic wells. The new approach suggests eliminating the need for stripping out and re-manifolding by lifting the well while it is connected and flowing to the gas plant. Many challenges were encountered during this effort, including the limited space for spotting equipment around the well connections, well control, and well response monitoring. In addition, it was difficult to overcome the downstream pressure across the pressure control valve (PCV) to allow unloading the well under its own pressure drive. The operation served as a benchmark for future wells. The operation turned out to be a huge success in terms of cost and safety. The avoidance of strip-out, re-manifolding, testing package, and producing to the gas plant instead of flaring resulted in significant cost avoidance and reduction in production time. This paper will provide an insight on the reasons behind selecting this well as a potential candidate for the job. It will also shed light on the risk assessment aspects, both technically and environmentally, and the operational safety backup plan that was thoroughly discussed and implemented. In addition, the challenges faced throughout the whole process of selecting the well, conducting risk assessment, issuing the Management of Change (MOC), designing the rigless program, and finally commencing operations will be discussed to ensure obstacles in future operations can be minimized. At the end, lessons learned and recommendations will be shared to ensure that the highest levels of operational efficiency are maintained for similar cases in the future.