Boreholestresses and deformations can be the cause of numerous high cost drill lng, co= Pletl On. and product ion problems, including: 1. 2.3. f+. 5.Drill string and cas~ng sticking through borehole contraction, Gas migration due to ineffective sealing tetween casing, cement, and borehole wali, Breakdown and possible mDbili Zat iOn of fo:-.at ion material leading to impaired product ivity, :njection,

Due to the ever-increasing demand for oil and gas, it is becoming more evident that getting the most out of the reservoir is crucial. For years, wells were drilled vertical or deviated, but horizontal and extended-reach trajectories are gaining more prominence. While the objective is to gain more access to the reserves, often the past methods of completions simply were not viable. In deviated wellbores, cased and cemented liner applications are difficult to obtain a good cement bond with the formation, and the inherent near-wellbore damage associated with cementing can lead to costly workover and stimulation treatments. Thus, open-hole completions are becoming more acceptable as the primary completion of choice. This paper will discuss the benefits of gaining as much contact with the reservoir as possible to create maximum drainage. It also will cover completion solutions (turnkey) that have been deployed around the world to better optimize recovery. Case histories will be provided that include multi-stage fracturing with swellable packers, inflow control devices with mechanical-set packers, geothermal hook-ups with openhole anchor, and multilateral completions with sand control and zonal isolation. Introduction In today's oilfield it is important to gain the most contact with the reservoir to ensure the maximum drainage. Cutting-edge measurement-while-drilling (MWD) systems allow operators to accurately place the well within feet of the planned location. Often the well geometry will take a more horizontal profile in the producing interval because the payzones are tighter and shallower than wells of the past. In addition, one well can now be the conduit for many producing reservoirs with the use of multilateral completions. As the wells are becoming more complex and inherently more costly, it is important to simultaneously minimize risk and maximize recovery. The solution to all of these challenges is to complete an openhole production zone to eliminate any operational risk associated with cementing and perforation. No two wellbores are the same and with the growing advances in technology, openhole completions systems can be customized to meet operators' specific needs or demands. Completions may involve multi-stage fracturing using reactive element packers, inflow control with mechanical-set packers, multilateral completions with zonal isolation, and geothermal completions with openhole anchoring. Multi-Stage Fracturing With Reactive Element Packers One of the most versatile tools for providing zonal isolation is the reactive element packer (REP) which uses wellbore fluid exposure to activate and seal-off desired zones. The reactive element (sometimes referred to as swellable packers) is an easy alternative to other packers because they require no intervention to set. This further simplifies the completion phase and therefore reduces additional risk from pumping and running an inner string. In recent years this technology has been widely adopted for use in openhole multi-stage frac applications. When used in conjunction with ball-activated sliding sleeves (as seen in Figure 1), an entire horizontal section (with up to 12 stages) can be pumped continuously without the need to run bridge plugs.

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. P. 401^

Boreholestresses and deformations can be the cause of numerous high cost drill lng, co= Pletl On. and product ion problems, including: 1. 2.3. f+. 5.Drill string and cas~ng sticking through borehole contraction, Gas migration due to ineffective sealing tetween casing, cement, and borehole wali, Breakdown and possible mDbili Zat iOn of fo:-.at ion material leading to impaired product ivity, :njection,