Reservoir sections in MRC (Maximum Reservoir Contact) & ERD (Extended Reach Drilling) wells are mainly designed to drill 8 ½" hole, because of drilling limitations with smaller hole size. However, slim hole sizes offer opportunities to revitalize existing wells using re-entry drilling techniques in association with MRC and ERD designs. This paper discusses the best practices to be implemented in order to mitigate risk, reduce complexity and ensure improved drilling performance. Re-Entry wells in the field have a risk of well integrity issues such as corroded 9 5/8" casing. In order to mitigate this risk, the corroded 9 5/8" casing should be covered by 7" liner & tied-back to surface before drilling reservoir section. In this situation up to 18,000 ft of 4" DP is used in the wells to drill 6" hole and run 4 ½" lower completion. Offset well analysis, whip stock selection criteria, BHA design, drilling fluid selection, drilling and tripping practices based on torque & drag and hydraulics calculations are most important to achieve the well objective. The Slim hole MRC well was completed without any issues and achieved good drilling performance. It was observed that the actual drilling parameters such as torque, drag and stand pipe pressure were less than simulated parameters. NAF was selected in the section to reduce the friction factor, while motorized RSS and a reamer stabilizer were used in the BHA to reduce torque, drag and ensure a smooth well profile. A back reaming practice was implemented in hole section to reduce dog leg severity and the open hole was eventually displaced to viscosified brine to minimize the friction factor for running the 4 ½' lower completion. 8500 ft of 6" hole section was drilled and TD was reached at +/- 19,000ft within 50 days including recovering the existing completion, drilling 8 ½" & 6" hole and running completion. This paper aims to contribute to the oilfield industry by sharing the successfully implemented engineering design and operation execution methodology to overcome the complexities present in Re Entry Wells MRC/ERD wells required to be drilled with slim hole conditions under an optimal cost, time effectiveness and low risk.

A Major Operating Company in UAE planned and drilled a challenging 6 inch horizontal drain after crossing twenty-seven formation sub-layers. The heterogeneity of pore pressure varied from equivalent mud weights as high as 10.6 ppg to as low as 7.1 ppg across the exposed reservoirs. Control of the equivalent circulating density (ECD) values to safely drill across these multi-reservoir sections and diverse reservoir pressures was one of the top challenges on this well, as the fracture gradients (FG) ranged from 13.5 ppg across the competent reservoirs to as low as 11ppg across the fractured reservoir section. The offset well data review show that 4 out of 6 wells encountered moderate, severe and total losses with mud weight (MW) ranging from 11 ppg to 11.3 ppg, which were cured by using heavy LCM treatments and in some cases, after several failed attempts to cure losses, cement plugs were used. Historically, the average time spent curing total losses in these wells varied from 2-3.5 weeks causing well cost increments as consequence of this non-productive time. All of the above, without mentioning the extra efforts, resources and risks were faced due to well control and stuck pipe events which occurred on those wells. Engineering and Operation teams worked together to engineer a solution to drill this well in one run while safely maintaining the well under control and managing the losses. The Bottom Hole Assembly (BHA) was designed to withstand the well challenges including multiple contingency options. These options allowed:Improving hole quality while tripping using a special type of eccentric reamer stabilizer.Pumping various LCM concentration scenarios through a multi-cycle circulation valve. In addition, a special type of float valve was placed on the top of the BHA as barrier, stopping back flow under surface backpressure or kick scenarios.Optimizing mud weight by using formation pressure while drilling (FPWD) and monitoring both equivalent circulating density ECD and equivalent static density (ESD) by pressure while drilling tools. The drilling fluid was loaded with non-damaging loss circulation material without compromising the MWD/LWD limits. Additionally, the mud rheology was carefully selected and monitored to achieve the desired ECD. On surface, a managed pressure while drilling system was deployed to give control on reservoir pressures. In instances of influx, MPD allows to early detect any kick and controlled by surface back pressure without requiring shut in for applying standard well control techniques. Keeping the well under control by surface back pressure (SBP) during connections time (flow–off). Additionally, MPD also enables the contingency of applying pressurized mud capping in case of unable to control the losses. As decision point, a loss management plan was prepared and implemented. Also, a dynamic formation integrity test was planned and performed to calibrate the fracture gradient across the loss zones. The problematic zone was successfully drilled with one BHA in under six days (5.73 days). The estimated savings for the company were 8 days, which equates to ±1MMUS$ after including the MPD cost which increased the well cost by 200MUS$. To further complement the outright savings, the engineered solution managed to safely stave off operational complications as well as incurring the related complexities and non-productive time (NPT) as recorded on the offset wells. Additionally, well was successfully landed and geo-steered across the target formation and 4½ in liner was run and cemented off-bottom avoiding the need to develop a slot recovery scope on this well with an extra duration of +/-35 days. The engineered solution provided a high level of preparation and contingencies within the BHA, Managed Pressure Drilling Equipment, real time monitoring, mud and cement formulation. The applied techniques allowed the operating company to successfully execute this challenge well within the proposed time and budget.

Slot recovery operation can be considered as one of the most time consuming operation. Cut and pull casings, or milling casings have been carried out as typical method of slot recovery. However there are a lot of risks with this typical method such as poor progress of milling, damaging top drive due to high vibration while milling or sudden string jumping up while overpulling and possibility of string stuck caused by poor hole cleaning while milling. We have completed slot recovery operations on numbers of wells, but there were a lot of troubles caused by above mentioned adversaries on rig equipment and taking a lot of time to complete operation. There are several kinds of new slot recovery technologies that may save rig time and less harmful than conventional method. Casing Pulling Tool (CPT) is one of the new technologies which eliminates or mitigates risks mentioned above. CPT has piston internally and it is activated by applying pressure inside string. CPT is run with casing spear and drill pipes. Once spear is engaged with casing and apply pressure inside drill string, CPT provides pulling force on casing. Pulling force is varied depend on the applied pressure and maximum available pulling force is more than 1,000 kips. Hence upper part of string is anchored at rotary table by slips, pulling force is applied on casing and drill string below rotary table. This means no pulling force is applied on top drive and minimize the chance of getting damage on it. As an actual case, we could successfully recover 13-3/8" casing by CPT without having any troubles and complete slot recovery operation with saving rig time compared to the conventional methods. This paper introduces the details about the case mentioned above.

In multilayered reservoirs, major focus has been on the usage of smart well completion technologies to help improve recoveries, particularly with technological improvements and an increasing expanse of opportunities in more challenging and rewarding assets. The fundamental focus has been to design well completions that integrate several surface/subsurface sub zones and automate the flow control from each zone. In Multi zone Smart Completion Wells where significant investment is made to complete smart wells with remotely controlled inflow control valves (ICV), reservoir sweep & drain accessibilities becomes decisive when evaluating the efficiency of recovery and long-term field development strategy. Smart completion designs for multi-lateral wells present many challenges in terms of completion deployment and interventions in life of well. The complexity of operations increases with deviation, type of completion equipment, number of zones and planned interventions. In offshore, UAE a similar multilateral well was designed to be completed with 4 zone smart completion and had a mandatory requirement of accessibility to lower most drain (for future interventions) with the ability to plug the lower drain till future requirements arises. A solution is to utilize nipple & blanking plug in lower most drain, which was implemented in this well. Upon successful deployment of completion, plug was retrieved on coil tubing and lower drain accessibility was confirmed. However, during re-installation of blanking plug on coil tubing in deviated section, issues were encountered to pass through the ICV profiles. In attempts to pass through ICV profiles, blanking plug and running tool got disconnected from coil tubing, leaving the fish inside one of ICV valve. Several attempts were made to retrieve the blanking plug with rig on coil tubing without success by using thru-tubing fishing equipment options available in country. Well was suspend to work-out fishing strategy & evaluate availability of fishing equipment worldwide. Consideration was done for design and manufacture application specific fishing tools to perform workover with barge for such smart completion, as it includes a number of downhole components that makes its retrieval more challenging, and there are no standard procedure or provision in place to retrieve such complex completions in highly deviated section. A barge was mobilized with coil tubing, which performed the fishing operation as planned. Careful selection of equipment's, BHA and operational parameters resulted in successful retrieval of blanking plug & running tools. Accessibility to well was gain and confirmed. This paper presents the situation that was faced, the remedial work done to complete well, fishing operations and the subsequent factors considered for choice of equipment and operation on well. This paper concludes a detailed account of factors to consider for planning smart completions in horizontal multilateral wells & the successful fishing operation – an excellent example of how careful planning, dedicated project management, specialized design fishing tools, experienced personnel and a collaborative relationship between team's leads to a successful operation and prevented an extremely expensive workover of a high technology completion well.

The 3,000 ft long lateral holes drilled through water-injected area in the carbonate reservoir in the offshore Abu Dhabi have been forced to implement hard backreaming. The abnormal extra operational time has been taken due to poor performance in the operation to pull out a bottomhole assembly after drilling to the total depth. The study aims to analyze root-causes of the hard backreaming through the carbonate reservoir in the studied field. The speed of tripping-out was analyzed every stand of drill pipe by using time domain data of movement of traveling block. The correlations between the speed of tripping-out and rock characteristics such as porosity and constituent minerals in rocks were investigated. Hole shape was analyzed in the representative intervals of low trip-out speed using 16-sector caliper derived from azimuthal density logging. Stress concentration around the borehole wall was also analyzed using geomechanical model. The investigation revealed that hole shrinkage due to plastic deformation of the borehole wall was the most possible root-cause of the hard backreaming in the carbonate reservoir. Namely, BHA had to ream up deformed borehole wall in tripping-out. From the viewpoint of rock characteristics, the speed of tripping-out was found to be lower in the specific geologic layers with higher content of dolomite. This is because dolomite rocks cause larger resistance in reaming it in tripping-out since the strength of dolomite rocks is larger than that of limestone. Based on our findings, use of reamers on bit is found to be the better solution to improve the tripping-out performance in the problematic geologic layers instead of conventional operational attempts such as spotting of acid and use of high viscous fluids in hole cleaning. In addition, optimization of the design and position of reamers and stabilizers is essential to succeed in the future 10,000 ft long extended-reach wells in the studied oil field.