A large operator of a brown field offshore in the middle east has decided to provide full lower Completion accessibility and ensure prevention of open hole collapse as it can lead to various gains throughout the life of the well. Among those benefits, it provides a consolidated well bore for various production logging & stimulation tools to be deployed effectively, as well as full accessibility, conformance control and enable to provide production allocations for each zones. However there are multiple challenges in deploying lower completion liner in drains involving multiple reservoirs and geo steered wells: Well Bore Geometry, dog legs/ tortuosity etc. & differential sticking possibilities and of course the open hole friction. Due to the size of the open hole, restricted casing design and utilization of limited OD pipes further add to the complications of deploying the Lower completion liner in such brown Field wells. This paper intend to review the multi-step methodology approach implemented in recent years by the company to effectively deploy 4-1/2" Liner in 6" Horizontal Open Hole section. Among the techniques used to assist successful deployment of lower completions are: Improving hole cleaning, ensure smooth well bore with the use of directional drilling BHA, reduction of the Open Hole friction by utilizing Lubricated brines, fit for purpose Centralizers, use of drill pipe swivel devices to increase weight available to push the liner & reduce buckling tendency. With the length of open hole laterals reaching up to 10,000 ft for 6" Lower drains, open hole drag, friction & cleanliness are major components that causes challenges in deploying the Liner till TD. The use of specially formulated brines with fixed percentage of lubricants proved to significant reduce friction compared to the drilling mud used for drilling the horizontal drain. The combination of low friction brine with proper centralization / standoff which resulted in reduced contact area with the formation has also shown good results in preventing differentials sticking while running the liner through multilayer reservoirs having significantly different reservoir pressures. Another major constrain to deploy the lower completion liner in this offshore field is the very nature of the wells being primarily workover. This involves generally Tie back liners run to shallow depths to restore the integrity of wells. This limits our ability in the selection of drill pipe that can be used as only smaller OD drill pipes and HWDP can be utilized in order to deploy the Liner to bottom. On many occasions this provides only limited weight to push the Liner down to TD and impact our ability to set the liner top packer. Drill pipe rotating swivel devices have been utilized to improve our weight availability & transferability to push the liner down and to set the liner top packers. In order to provide independent deactivation mechanism for the drill pipe swivel and to have complete success in our liner deployments, a dedicated ball activated sub was designed to deactivate the swivel acting as back up in case primary deactivation methods fails during liner setting. The combined use of all these techniques enabled the company to deploy 4.5" Liners in 6" Horizontal drains with high success in this offshore Brown Oil field of UAE. This resulted in better well construction and complete access to lower drains over the life of the wells.

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.

A large operator of a brown field offshore in the middle east has decided to provide full lower Completion accessibility and ensure prevention of open hole collapse as it can lead to various gains throughout the life of the well. Among those benefits, it provides a consolidated well bore for various production logging & stimulation tools to be deployed effectively, as well as full accessibility, conformance control and enable to provide production allocations for each zones. However there are multiple challenges in deploying lower completion liner in drains involving multiple reservoirs and geo steered wells: Well Bore Geometry, dog legs/ tortuosity etc. & differential sticking possibilities and of course the open hole friction. Due to the size of the open hole, restricted casing design and utilization of limited OD pipes further add to the complications of deploying the Lower completion liner in such brown Field wells. This paper intend to review the multi-step methodology approach implemented in recent years by the company to effectively deploy 4-1/2″ Liner in 6″ Horizontal Open Hole section. Among the techniques used to assist successful deployment of lower completions are: Improving hole cleaning, ensure smooth well bore with the use of directional drilling BHA, reduction of the Open Hole friction by utilizing Lubricated brines, fit for purpose Centralizers, use of drill pipe swivel devices to increase weight available to push the liner & reduce buckling tendency. With the length of open hole laterals reaching up to 10,000 ft for 6″ Lower drains, open hole drag, friction & cleanliness are major components that causes challenges in deploying the Liner till TD. The use of specially formulated brines with fixed percentage of lubricants proved to significant reduce friction compared to the drilling mud used for drilling the horizontal drain. The combination of low friction brine with proper centralization / standoff which resulted in reduced contact area with the formation has also shown good results in preventing differentials sticking while running the liner through multilayer reservoirs having significantly different reservoir pressures. Another major constrain to deploy the lower completion liner in this offshore field is the very nature of the wells being primarily workover. This involves generally Tie back liners run to shallow depths to restore the integrity of wells. This limits our ability in the selection of drill pipe that can be used as only smaller OD drill pipes and HWDP can be utilized in order to deploy the Liner to bottom. On many occasions this provides only limited weight to push the Liner down to TD and impact our ability to set the liner top packer. Drill pipe rotating swivel devices have been utilized to improve our weight availability & transferability to push the liner down and to set the liner top packers. In order to provide independent deactivation mechanism for the drill pipe swivel and to have complete success in our liner deployments, a dedicated ball activated sub was designed to deactivate the swivel acting as back up in case primary deactivation methods fails during liner setting. The combined use of all these techniques enabled the company to deploy 4.5″ Liners in 6″ Horizontal drains with high success in this offshore Brown Oil field of UAE. This resulted in better well construction and complete access to lower drains over the life of the wells.

Drilling and completion operations in depleted reservoirs, are challenging due to narrow margin between pore and fracture pressures. Therefore, Ultra-Low Density Reservoir Drilling Fluid (RDF) with optimum parameters is required to drill these wells safely. Design and effective field application of a sound engineered fluid solution to fulfill these operational demands are described. Ultra-Low Density RDF NAF with minimal fluid invasion characteristics was developed after extensive lab testing, to cover the fluid density from 7.2 – 8.0 ppg. The fluid properties were optimized based on reservoir requirements and challenging bottom-hole conditions. The design criteria benchmarks and field application details are presented. Fluids were stress tested for drill solids, reservoir water and density increase contamination. Multi-segment collaboration and teamwork were key during job planning and on-site job execution, to achieve operational success. For the first time in UAE, a major Offshore Operator successfully applied an Ultra-Low Density RDF-NAF, which provided remarkable stability and performance. The fluid was tested in the lab with polymeric viscosifier alone and in combination with organophilic clay. In order to gain rheology during the initial mixing, about 3.0 ppb of organophilic clay were introduced to system along with the polymeric viscosifier. Later, all the new fluid batches were built with polymeric additives alone to achieve target properties. A total of 10,250 ft of 8 ½" horizontal section was drilled to section TD with record ROP compared to previous wells in the same field, with no fluids related complications. With limited support from the solid control equipment, the team managed to keep the density ranging from 7.5 ppg to 7.8 ppg at surface condition, using premixed dilution. Bridging was monitored through actual testing on location and successfully maintained the target PSD values throughout the section by splitting the flow on three shaker screen size combination. Due to non-operation related issues, hole was kept static for 20 days. After such long static time, 8 ½" drilling BHA was run to bottom smoothly precautionary breaking circulation every 5 stands. Finally, after successful logging operation, 6 5/8" LEL liner was set to TD and the well completed as planned. Success of this field application indicates that an Ultra-Low density fluid can be designed, run successfully and deliver exemplary performance. Lessons learned are compared with conceptual design for future optimization. Laboratory test results are presented, which formed the basis of a seamless planned field application.