Summary Underbalanced drilling with casing (UBDWC) is improving drilling performance dramatically in south Texas fields. This approach allows drilling of depleted and high-pressure sands intermingled within one hole section, resulting in significantly less-expensive well plans. Drilling cost reductions of 30% have been realized. Smaller-reserves targets are viable—a key advantage in the mature south Texas Vicksburg play. Introduction Shell has developed and operated gas fields in south Texas for the past 50years. These 10,000 to 16,000-ft, high-pressure/high-temperature wells normally have initial shut-in tubing pressures approaching 10,000 psi when virgin pressure sands are completed. The bottomhole temperatures range from 280to 400oF. Most wells have multiple low- permeability pay sands, which require massive hydraulic-fracture treatments to produce economically. Each pay interval is fracture treated in a separate stage, and the production from all the sands is commingled. Most current drilling activity is in and around mature fields in which large volumes of gas have been produced. Severe reservoir-pressure depletion intermingled with high pressure is often encountered. The presence and level of pressure depletion is difficult to predict because of complex geology, low permeability, and production commingling. The UBDWC approach was first applied to a slimhole re-entry program that began in 1995.These re-entries were either sidetracks to replace wells that failed because of casing damage or wells that were deepened to new objectives. The re-entries are normally half the cost of a new well, allowing smaller reserve targets to be drilled economically. The wells were sidetracked out of the existing 5- or 5½-in. casing and a new string of2?-in. casing was run and cemented. By 2000, the remaining re-entry candidates were difficult to drill, with lost-circulation and well-control problems more common. The program was becoming uneconomical because of the inability to set liners in the small hole size. UBDWC1-3 was applied to resolve these problems, and 10 re-entries have been drilled this way since2001.The low-permeability Vicksburg sands allow operations with a higher underbalance than would be possible in most other applications. The learnings from the re-entry program have been transferred to the drilling of new south Texas wells. This has allowed smaller casing programs and the elimination of liners, and trouble cost has been reduced, resulting in a cost savings of up to 30%.UBDWC requires little rig modification and standard off-the-shelf equipment; it has been applied on rigs equipped with rotary tables and top drives. Using the Intl. Assn. of Drilling Contrators' Underbalanced Operations Classification System, these operations are Level 5-B-5.
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.
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.
Recent technological advances are driving casing and liner drilling from a niche market into the mainstream environment. Improved connections, tubulars, advances in rig technology and pipe handling have enabled operators to consider drilling with casing/liner as an option on many new wells 1,2 . Escalating deepwater costs and the need to further reduce onshore drilling expenses in low cost fields continue to push the technology forward.In a mature South Texas field, an operator discovered the difficulties of drilling into formations with weak matrix strengths, loss circulation zones, and tight pore pressure/fracture gradient windows.These issues have deemed the field sensitive to aggressive drilling techniques and the operator has been forced into a conservative drilling program with reduced flow rates and lower weight-on-bit capacity. The operator needed to reduce trouble time, lower costs and make the wells more economically feasible.A service company introduced a new liner drilling system solution to get through the extensive problematic zones. The system is engineered so the operator can ream to bottom and then continue drilling with the liner to the required target depth. The system is comprised of a drillable fixed cutter casing bit and a drill-in liner assembly designed to handle the rigors of a drilling environment (rotation, reciprocation and drilling torque). The liner system utilizes a running tool that allows the liner to be used in drilling mode handling all the required drilling loads without fear of release. Once at desired setting depth, the hydraulically balanced liner-running tool is released with a setting ball. The casing bit is manufactured from a specialized steel alloy that allows technicians to braze polycrystalline diamond compact (PDC) cutters directly to the one-piece bit ensuring a robust cutting structure capable of efficiently drilling new formation as well as reaming existing hole. The system allowed the operator to drill in the liner to TD, cement, and then drill out to the next casing point.To date, nine intervals have been drilled with this system in South Texas. This paper will focus on the problems encountered in the field, the development work in establishing a solution for the operator, the results attained, and lessons learned through using this new technology. TX 75083-3836, U.S.A., fax 1.972.952.9435.
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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