Different Reservoir Pressures in Multi Reservoir Hole Section Conquered by Advanced Planning Techniques
Freddy Alfonso Mendez Gutierrez; Islam Khaled Abdel Karim; Mario Ramon Oviedo Vargas; Mohamed Abdulrahman Alzaabi; Salim Abdalla Al Ali; Takahiro Toki; Jeughale Ramanujan; Scott Wagstaff; Hisaya Tanaka; Bilal Iftikhar; Javier Ernesto Torres Premoli; Khaled Abdelhalim; Daniel Juarez Moreno; Anurag Yadav; Imran Muhammad Chohan
SPE - Society of Petroleum Engineers
May 25, 2021
SPE/IADC Middle East Drilling Technology Conference and Exhibition, May 25–27, 2021
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.