In late 2010, Shell began an Eagle Ford appraisal program at Piloncillo Ranch in South Texas. These wells are 8,500’ – 9,500’ TVD horizontals, with an average total depth of 14,500’ MD. Their primary target is the Cretaceous Eagle Ford shale. The Shell leases are located in the gas-condensate window. Shell is currently running a five rig development program. Initially, reservoir pressures were thought to be in the 12.5 ppg range, but Diagnostic Fracture Injection Tests (DFITs) showed the actual pore pressure to be greater than or equal to 14 ppg. Initially, underbalanced drilling techniques were used to drill the 14-14.5 ppg formation with 11 ppg oil based mud. The Eagle Ford has no natural fractures in this area. As more wells were drilled, however, completion fracturing of offset wells began to cause well control problems, as induced fractures were encountered in horizontal sections during drilling. Initially, it was thought that additional casing strings would be required to deal with the higher pressures and flow capability of the 14-14.5 ppg fracture; however, through well control modeling and experience with underbalanced drilling in other tight gas environments, tripping and heavy pill spotting procedures were developed that allowed the wells to be drilled with the initial casing program. This paper will describe the development of fit for purpose well control techniques used to drill underbalanced horizontal wells in the Eagle Ford shale gas play. It will discuss how the characteristics of tight shale formations in horizontal wells resulted in a different approach to well control and tripping procedures. Several simple techniques for establishing an understanding of real time data have helped to make decisions in the field with current information: Institute a dual density system to stop reservoir flow and prevent up-hole lossesCreate a Horner Plot for distinguishing ballooning from reservoir flow if losses are experiencedCreate a mud weight vs. influx flow plot for predicting flow changes with mud weightAscertain how the influx rate and location affect the time at which it would a take a well to unload to dry gas The paper will also describe the software modeling used to determine influx responses and the methodology developed around it. This methodology is applicable to other tight shale formations drilled horizontally and developed around the globe. These procedures can significantly reduce non-productive time and minimize serious well control events on horizontal shale wells when properly followed.
TX 75083-3836, U.S.A., fax 1.972.952.9435. AbstractMany wells drilled today have complex well paths or are drilled through depleted or problem formations. In these wells, the liner may have to be reamed or drilled in, either to pass through the previously drilled hole or to make a new hole in the problematic formation. In many cases, the liner cannot be run to bottom as planned because unexpected problems are encountered. This situation can cost millions of dollars due to the required remedial work and deferral of production. This paper will discuss a rotary liner drilling application utilizing an expandable liner hanger in the Gulf of Mexico. The primary objectives of the trial were to develop a better understanding of the status of current technologies and how these apply to the challenges of this type of application. ProposalSignificant volumes of oil and gas remain undeveloped within producing fields as secondary objectives that require cost effective re-development. In recent times, it has become economically and technically feasible to access and produce these reserves through sidetracks of the original wells. These sidetracks may be completed as producing wells or water/gas injectors.Conventional methods require drilling through the reservoir, often inducing losses in the depleted interval, pulling out of the hole at a controlled rate, and then run the liner while experiencing losses. Furthermore, conventional liner running methods do not have the capability to rotate the liner while running in the hole, increasing the risk of being differentially stuck across a depleted sand. The ability to drill the liner in a rotary mode across the depleted sand can minimize the risk of losses associated with conventional practices while eliminating the need for a mud motor, which in turn allows the liner to be drilled at low flow rates with low associated equivalent circulating densities (ECD) 1,2 . Furthermore, it minimizes the amount of time that the formation is exposed, further reducing the risks of borehole collapse or trouble while running the liner to bottom. The expandable liner hanger allows hanging the liner and setting the element in one step, eliminating a potential cement squeeze job or an additional trip for a liner top packer.
Significant drilling performance improvement was achieved over a two year period in the HPHT Haynesville Shale Play in North Louisiana. Technical challenges include drilling through abrasive, high compressive strength formations, bottom hole temperatures exceeding 360°F, sour gas and shut-in surface pressures near 10,000 psi. The wells are horizontal with 12,500 to 14,500 ft TVD, and 16,500 to 18,500 ft MD. The application and optimization of managed pressure drilling (MPD), underbalanced drilling (UBD), hard rock drilling, casing drilling, casing design and installation procedures will be discussed.
In the development of onshore gas fields SWEPI LP (Shell) has encountered margins in which the difference between dynamic ECD and static BHP is the difference between lost circulation and influx. The limits imposed by those conflicting conditions create narrow mud weight windows. The reasons for the tight pore pressure and fracture gradient windows in these vertical and horizontal onshore HPHT tight gas environments vary. Some are old fields challenged by depletion. In the case of South Texas, the main problem is losses in the production hole due to depletion. The pressure in different zones is often difficult to predict due to complex geology further complicated by years of commingled production without knowing what each zone has contributed. In some of the new shale plays, like the Haynesville, slim hole well plans are used which have problems with low kick tolerance design and unexpected kicks through fractured intervals. These pose unique well control challenges to minimize non productive time. In all of these wells, there is the high cost associated with losing mud and/or constantly changing mud weights to prevent losses or influxes. To mitigate these potential problems, Shell has recognized the use of the Managed Pressured Drilling (MPD) concept which enables the use of the lowest possible mud weight to drill these challenging wells. By lowering the mud weight and manipulating the annular pressure during drilling, the risk of mud losses and/or quick sudden transitions into over-pressured zones is reduced. There are some direct benefits of drilling with lower mud weight such as higher ROP's, lower stand pipe pressures and lower circulating temperatures. In addition, there are lower ECD's and higher pump rates that improve the hole cleaning. Field trials using a fully-automated MPD solution were performed by Shell in South Texas and North Louisiana Haynesville from late 2010 to mid 2011. This paper describes implementation of a fully automated MPD, small rig foot print system which incorporates a Rig Pump Diverter (RPD) that allows smooth transition from circulating to non-circulating down hole during connection while maintaining continuous rig pump circulation. Results from the field trials will be documented in the paper. We will show the impact of drilling with lower mud weights on well performance. Additionally, a comparison of vertical and horizontal HPHT wells that were drilled conventionally and wells drilled using MPD will be made showing the effects of drilling with lower mud weights on ROP, down hole circulating temperature, ECD, stand pipe pressure and pump rate.
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