Well XX-1 is a newly drilled Oil producer well in offshore east coast of India. Lower completion containing Formation Isolation Valve (FIV), Standalone Screens with integral SSD's & swell packers was run in 6″ Open Hole & set on screen hanger packer. The FIV, packer & Production casing was then pressure tested to 3000 psi, during which pressure drop of ~15 psi/min & continuous return from secondary annulus ~1 litre/min was observed. The above indicated possible communication between 7″ production casing & 9-5/8″ surface casing. The leak depth was investigated using a drillpipe conveyed single run multiple set mechanical packer & it was established that the bottom connection of Cross over below 7″ casing hanger pup joint was leaking. Leak in production casing was a critical well integrity threat. Further, the well was designed to be operated on gas lift. There was no immediate remedy available to restore the production casing integrity. It was decided to complete the well and produce with adequate controls without gas lift till the casing leak was repaired. Meanwhile, extensive search and literature review was done & various options to repair the casing leak, both mechanical and chemical, were evaluated. Considering the expensive mechanical repair and associated high uncertainty, Pressure Activated Liquid Sealant was proposed as economical alternative. The sealant works on the principle of polymerization and cross linking when subject to pressure drop. This sealant process has proven to be a successful long-term repair method for completion equipment. Utilizing a combination of fluid density control and packer fluid compressibility, the sealant was injected into the annulus casing valve then spotted & squeezed into the leak at 2500 psi and allowed to cure under pressure for 80 hrs. The production casing was then successfully pressure tested with both liquid and gas and the integrity was confirmed. It not only prevented expensive work-over saving > 10 MMUSD, but the quick remedy also allowed the well to be brought online at a higher production rate ~ 1000 BOPD incremental. It has proved to be a reliable solution to well integrity problem.

Ravva is a mature field located offshore east coast of India with over 20 years of production history from Middle Miocene sandstone reservoirs. During the development phase of the field, Late Miocene (LM) sands were intersected in few wells at shallow depths. Due to the presence of more promising and critical zones below, these sands were not completed and fell above the production packer and behind the production casing. The marginal reserves in these sands did not justify workover operation to complete it. Rigless options were studied and a shut-in well was selected for implementation. In order to safely complete and access the bypassed shallow sands, a vessel based pumping operation was planned to place a cement packer in the tubing – casing annulus. The slurry was circulated into the production casing/tubing annulus through a circulation SSD installed above the production packer.The cement packer was thus placed across the zone of interest. Designing of the cement slurry was based on reservoir parameters and the setting time was optimized to prevent reversing of the slurry back into the tubing. The cement mix had a bonding agent to exhibit good metal-cement bonding providing prolonged endurance of the cement with the capability of holding the expected pressure differential. The cement packer emulated a production packer providing zonal isolation for the new completion. Size of the platform precluded spotting of the complete Coil Tubing spread on the platform. High cost prohibited catenary coil tubing operations. As an alternative, the pump spread was placed on a DP vessel and the coil tubing unit was spotted on the platform. A high pressure hose running up from the vessel to a standpipe on the main deck of the platform formed the main conduit for fluids being pumped from the vessel into the CT or wells. Onsite mixing of the cement slurry on the vessel required detailed planning and execution. The well was activated & tested at rates of 1500 bopd with no integrity concerns till date. This paper will emphasize on the operational procedure and challenges of successfully completing the zone and bringing the shut-in well online. The execution of this operation was done at 1/10th of the cost of a rig based workover. This has also opened up new opportunities to access similar bypassed reserves resulting in incremental production from reservoirs which would have otherwise been left untapped.

As energy demand continues to grow, it is amazing that more than half of world oil production comes from fields as old as 30 years. The Cambay offshore fields off the coast of Gujarat, India started producing gas in 2002 and oil 2005. The production of Oil was possible through geophysical studies that led to incremental recoverable volumes. The oil wells with cased hole perforated completions however have a sanding problem after a few years of production leading to rapid oil production decline in the field as well as associated sand production issues. This paper presents the result from implementing the simultaneous gravel packing and hydraulic fracturing of a well commonly known as "FracPacks" in the industry on a sanding well in the field and a comparison to 2 other wells with different completion techniques. The paper outlines the challenges faced with data collection, the design methodology, an overview of operations and execution. The outcome of the FracPack treatment was a textbook tip screen out placement leading to a 76% increase in oil production with zero water cut and sand. The results demonstrate the benefits of contacting the reservoir beyond the critical matrix even in a 2.4 Darcy formation and highlights that FracPacks can be less sensitive to the procedures used for wellbore preparations.. The lessons learned from the Cambay experience add to the growing number of case histories which show that FracPacks are effective techniques for sand management in high permeability formations. FrackPack performance is compared to other techniques such as standalone screens and gravel packs, both in terms of production as well as production longevity. This study will highlight the importance of selecting the completion technique based on the reservoir challenges and the importance of considering constraints such as nearby water, logistics and other operational concerns.

XX-1 is a newly drilled well in Ravva field in eastern coast of India deviated to 70 deg and completed with a 6? Open-hole section. The initial completion plan for the sand prone well was to complete with stand alone screens for a single pay zone. During drilling, additional pay zones were encountered which necessitated completing the well with zonal selectivity using sand-screens with SSD. Selective completion required thru tubing intervention to operate the SSDs and produce selectively. Due to high deviation, intervening with slick line was very challenging whereas coiled tubing operations had its own limitations which are discussed in the paper. Hence it was decided to use Electro-hydraulic stroking tool along with motorable tool sections to convey tools in the high angle well. While shifting SSDs with hydraulic stroking tool, frequent held ups and stuck points were observed across all SSDs which made it difficult to confirm shifting key location with reference to SSD sleeve profile and hence confirm SSD opening. This resulted in unsuccessful attempts and tool failures. A detailed analysis was carried out to ascertain the probable cause of multiple held ups within the screen SSDs and to find out other ways to shift the sleeve. Trouble shooting was performed by combining video recording of shifting attempts at surface in an unused screen section along with engineering drawings of the screen. Based on trouble shooting results, shifting procedures were modified accordingly to precisely engage the shifting tool with SSD profile and SSDs were successfully opened. The stroker system also proved useful in opening a circulation SSD which enabled the well to be brought on line. This paper describes operational difficulties encountered and innovative ideas implemented to shift SSDs. It also reviews job planning, trouble shooting and execution, as well as reports the lessons learnt to derive best practices for future similar operations.

An offshore drilling campaign comprising of four development wells was conducted to augment oil production from a field located off the western coast of India. All four wells were designed to be sidetracked from existing depleted wells of the field. Historically, preparing existing wells in the field for side-track took ~4 days/well of a drilling rig and associated spread cost. This paper presents a case- history of conducting side-track well preparatory activities by a rig-less well intervention spread leading to significant time and cost savings. This method was also the first instance of such an activity being conducted in an offshore environment in India. Prior to actual side-track drilling from an existing well in a brown field, it is required to abandon the open zones in the existing well and prepare the well for casing window cutting for further drilling to a new sub-surface target. Typical preparation activities include multiple wireline runs to set/retrieve deep set and tubing hanger plugs, well killing, nipple-down X-mas tree, nipple-up BOP, wireline run to cut tubing, retrieval of existing completion and ultimately placement of cement plugs to abandon the parent wellbore. The routine approach in the organization for all previous offshore drilling campaigns was to utilize the offshore drilling rig for afore-mentioned well preparation activities. Substantial rig time was spent incurring the cost of entire rig spread for an average ~4 days/well equivalent to ~40% of total well completion time. The paper elaborates on rig-less operations set-up consisting of Cementing and Wireline Units utilized to conduct well killing, placement of cement plugs, production tubing cutting and nippling down X-mas tree prior to the mobilization of the drilling rig at the platform. The only operation left for the drilling rig was to pull-out the existing completion string and then drilling operations could commence. The execution of planned operations was flawless on three wells while one well posed technical limitation due to its high deviation. The rig less well preparation campaign was concluded incident free, ahead of schedule and within budget. This offline exercise prior to rig-move saved ~12 days of drilling campaign time which helped in cutting down on overall drilling campaign cost and also allowed the flexibility of adding more wells to the campaign within fair weather window. While this was an effort to simplify operations and save costly drilling rig-time in a side-track drilling campaign by conducting some very critical operations offline, these methods can also be adopted for planning well abandonment and decommissioning activities in a mature field.