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Objective This paper summarizes key engineering discoveries and technical findings observed during the staged development of a volcanic reservoir. Through out the development, 200 hydraulic fracturing diagnostic injection tests and 168 hydraulic fracturing treatments were performed. This program was conducted in one of the few commercially viable thick and laminated volcanic gas reservoirs in the world and were staggered in 5 separate campaigns over an 11-year period. Method, Procedure, Process Due to the low permeability of this gas reservoir, hydraulic fracturing was necessary for sustained economic productivity. As this massive laminated reservoir contained between 15 to 40 vertically separated pay sections, a key design consideration was to connect as much pay as possible with the least number of fracturing stages. Although a conventional plug and perforation frac technique gives full assurance of optimal fractures for every bit of pay, the completion cost would undermine the project's economics. Therefore, the limited entry technique was selected. The uncertainties and risks were evaluated to maximize the probability of success. Both methodologies were applied in successive campaigns. Staggering the project into 5 successive campaigns enabled adequate time to evaluate results, acquire data and execute. The results from these learnings are summarized in this paper. Results, Observations, Conclusions Over 60 DFITs (Diagnostic Fracture Injection Tests), ~90 SRTs and ~50 Mini-Fracs have been conducted. In addition to conventional fracture diagnostics tests, other techniques were applied with successful implementation. One such example was the utilization of multiple step rate tests within the same frac stage to evaluate limited entry efficiency. As a result of the test data, the number of clusters per frac was increased from 3 to 6, increasing the net pay coverage by about 65%. Another achievement was the reduction of the uncertainty in tubing friction and the evaluation of tubing friction increase due to the addition of proppant. This resulted in a cost effective method of reducing uncertainties in calculated BHPs, thus improving the overall understanding of fracture geometry. This paper also demonstrates that the integration of all of the collected diagnostic data, temperature surveys, frac simulation and geo-mechanic calibration resulted in increased contribution from more zones which was verified with production logs. This enhanced reservoir understanding greatly helped to save operational time and reduce cost. Completion improvements have resulted in an 80% increase in productivity and a 20% increase in EUR. Screen out rates have dropped from 33% to 5% between the initial and the most recent campaign. Novel/Additive Information A holistic workflow for conducting diagnostic injection tests in volcanic pays. Detailed analysis of limited entry controlled hydraulic fracturing and its efficiency. Representative case histories including, DFITS, Step rate tests, Mini Fracs, Temperature surveys and production logs to back up the production results.

Integrated field and well reviews followed by logical activities are being taken to address the voidage and declining pressure in Yibal. This is to ensure that target daily oil rates are achieved, and UR is maximized, in the largest oil producing asset in Oman, which delivers almost 15% of the total country production from a heavily faulted and fractured carbonate anticlinal structure, on stream since 1969. Water injection initiated in 1972 has gone through a series of stages; vertical oil phase injectors for lateral sweep, vertical aquifer injection for vertical sweep and later some horizontal deep aquifer injectors. The injection serves the dual purpose of pressure management and produced water disposal. The field has suffered negative voidage for quite some time, leading to rapid reservoir pressure depletion. Past studies have identified uneven vertical and lateral sweep due to uneven subsurface water distribution as a result of the complicated fracture and fault patterns as well as the subsurface hydro-dynamics and flow mechanisms. This has left the remaining oil in pockets that are becoming more difficult to produce. The high field average BSW has led to a situation where oil wells are closed in for surface facilities constraint and, or subsurface water injection capacity. Further, the uncertain water movement into producing wellbores makes production optimization activities risky. Recently, quite a number of injectors have been taken offline for integrity repairs and are only gradually coming back on stream after extensive and often expensive repairs. The implementation of a voidage replacement program which includes understanding the reservoir dynamics, identification of the worst hit low pressure areas, and prioritization of the short, medium and long term remedial activities is on going. Increased focus on gross offtake management, injection well stimulation, water shut off in producers, conversion of poor producers to injectors, and drilling of new injectors is showing returns in flattening of the decline rate of oil production. The issues around water injection as well as oil producer integrity are gradually being addressed. Several learning points for the implementation of the proper reservoir and voidage management have also been captured. The importance of human resources both in terms of numbers, level of experience and skills set, has also been recognized and the optimum balance of these is being worked on. Introduction The Yibal field (Fig 1), discovered in 1963 and brought on stream in 1969, currently produces oil (from the Shuaiba reservoir) and gas (from the Natih reservoir). Both streams are managed by different Asset teams.

This paper will describe how good project management and communications between the various project stake holders resulted in the successful completion of the Raageshwari 15 wells fracturing campaign. The 93 fracturing stages were completed under budget and in a shorter time frame than planned. The management of the project included multiple and diverse operations and equipment including perforating, wireline, well testing, hydraulic fracturing, HSE, and waste water management. The Raageshwari deep gas field (RDG) is a deep, tight, high condensate gas reservoir located in Rajasthan, India. The 15 wells were located on 3 separate pads within 2 km radius. Their location, in a sparsely populated arid part of India adds to the logistical challenges. Some of the key challenges during the project were: Key operations such as fracturing and perforating cannot be performed at night.Economic handling and disposal of waste water.Continuous supply of water suitable for fracturing and other wellsite operations.Limited space available on the well pads.Requirement for simultaneous operations involving high risk activities such as perforating and high pressure pumping.High CT cleanout frequency due to the requirement of underflushing the frac stages, close proximity of the adjacent stages, and the small volume in the 3 ½ inch monobore completions.Logistics and supply chain management in a remote location. Solutions for these obstacles included improved procedures, workflows and key technology introductions. These included: Simultaneous rig up to multiple wells.Simultaneous operations covered through Risk assessment and controls in place.Selective perforation technology to reduce perforating time.Mechanical evaporators and a robust CSR team for waste water management. The various optimizations resulted in a reduction in days per frac stage from 4 in the previous campaigns to 2 in this campaign. The project was delivered with 0 LTI (Lost Time Injuries), and a phenomenal HSE record due to robust safety procedures, frequent audits, safety drills etc. This paper will detail how the challenges in this project were overcome resulting allowing a high speed fracturing campaign to be successfully executed in a remote location.

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