An Offshore China/South China Sea operator wanted to optimize the use of a rotary steerable drilling assembly, simplify and reduce operational steps, and provide a larger reservoir wellbore. The operator elected to drill a single 8.5" wellbore and, in order to address a variety of issues and potential problems, change from a Cloud Point Glycol Drilling Fluid to a Drill- In Fluid (DIF) at the reservoir entry point. A reverse sequence solution engineering process was employed wherein planning began from the point of view of a completed well.
Introduction
Effectively addressing numerous potentially compromising elements within a plan to optimize both reservoir production and utilization of new drilling technologies can be achieved through Reverse Sequence Solution Engineering (RSSE).
Reservoirs with shale layers can cause serious problems during drill-in and completion operations. Reactive shales can lead to borehole instability during the drilling phase and, if not controlled, may plug gravel and screens in the completion phase. Further, DIF return permeability and lift off properties may be seriously impaired, resulting in reduced hydrocarbon production. Without properly sequenced well planning and fluid design, high rates of filtrate invasion, circulation losses, differentially stuck pipe and low production rates may result.
In order to minimize forming or accumulating unforeseen problems while a project is underway, it is sometimes critical to originate the planning sequence from the point of view of the desired end result. This paper attempts to provide an overview of a RSSE approach, which allowed incorporation of numerous new ideas, products, processes and technologies into an existing successful process. In addition, the details from a successful field test using the new elements will be presented.
Background
The operator had drilled a total of 12 wells culminating in horizontal sections in a variety of sandstone reservoirs at depths varying from 2000 to 3000 m TVD, with the deeper wells reaching nearly 4200 m MD. Of these, 4 were new wells while the remaining 8 were sidetrack re-entries. In all sidetrack cases, whipstocks were set inside existing 9.625" casing, and 8.5" sidetrack wellbores were exited from the casing. These 8.5" holes were drilled to designated reservoir entries, culminating at or very near a 90° angle. Then, 7" liners were run to isolate the entire 8.5" tangent wellbore. On some of the wells, following hanging and cementing the liner, 7" tiebacks were performed. The wells were then drilled horizontally into the reservoirs with conventional directional drilling assemblies using a water-based DIF containing a calcium carbonate bridging component. Depending upon reservoir characteristics, completion methods varied from open hole completions, to slotted or perforated liners, to pre-packed screens.
The operator had accumulated a history of consistently exceeding hydrocarbon production expectations when the reservoir was drilled using a specifically engineered DIF. Not surprisingly, the operator wanted to retain this DIF component in future wells.
Ten of the 12 wells, including all the sidetracks, were drilled with a platform rig that had initially been designed for workover purposes only. As a result, the rig was pushed to operational limits in drilling mode, with the primary limitations being overall string weight (top drive, draw-works and mast), pump pressure and output, top drive torque and speed, fluid handling and mixing capabilities, as well as fluid storage and circulating volume (Figures 1 and 2).
Regardless of these limiting factors, drilling progressed, with the directional profiles, depths and step outs reaching very challenging levels.
