The Lennox field is located in the Liverpool Bay area of the Irish Sea, lying predominantly within UKCS block 110/15. The reservoir is formed within the Triassic Sherwood Sandstone formation with top structure at approximately 2500 ft TVDSS. The field comprises a 140 ft thick oil rim underlying a dry gas cap and overlying an extensive aquifer (GOC @ 3257 ft TVDSS; OWC @ 3400 ft TVDSS). (Figure 1) A "delayed gas" development plan was devised for the field; oil being produced preferentially over the first six year period with all produced gas (solution gas + free gas) reinjected. Thereafter, the gas reserves will be produced.
The full Lennox project comprises ten wells: 9 horizontal producers plus one deviated injector. For the purposes of this paper, the scope of discussion is limited to the five first phase development wells.
To maximize oil recovery, the development wells were planned to be drilled horizontally through the reservoir at 3365 ft TVDSS, precisely 35 ft TVD above the oil water contact, and within a +/- 10 ft vertical window. Reservoir modeling indicated that this elevation maximized oil recovery by optimally delaying both gas and water coning / breakthrough into the wellbores. It was recognized however, that permeability variations within the reservoir formation and particularly the very high permeability zones >1 Darcy) would create flow conduits for early gas and water breakthrough. Minimizing the wellbore drawndown further delayed the potential breakthrough of gas and water, but some means of selective wellbore interval isolation was a prerequisite of the completion design.
Historically, three completion design options have been considered for similar horizontal well development projects, consisting of:slotted liner with no annular zonal isolationcemented and perforated linerslotted liner with cement-inflated External Casing Packer (ECP), annular zonal isolation.
Option 1 provided the lowest initial capital costs, but provided no means of easily effecting the required selective zonal isolation.
As summarized in Table 1, of the two remaining options, projected savings in well costs resulting from use of the ECPs instead of cementing and perforating, were approximately $450,000 per well, of which approximately $120,000 per well was attributed to being able to cement-inflate the ECPs in one trip with the liner running assembly.
Introduction
Although 7" 20-ft packers had been successfully cement-inflated in "one trip" with the liner hanger, 5-1/2" packers had never been inflated with this technique. Therefore, equipment modifications and procedures compatible with the packers, inflation tool, liner hanger, and liner setting equipment had to be developed.
Planning and project management are the most important factors in successfully cement-inflating packers in open hole. In this project, multiple 20 ft. packers (including as many as seven in one operation) were successfully cement-inflated between slotted sections of casing in "one-trip" with the liner setting operation. In the planning phase of the program, computer analysis was utilized to select a work string design that was capable of performing all required functions in one trip. Following design of the work string, an analysis was made to insure that all components and procedures were compatible.
In a one-trip system with a hydraulic liner hanger, the inner string must have pressure integrity after the hanger is set. This required design of a special ported sub that closes when the liner is released and the work string is pulled upward.
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