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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163984, "Eagle Ford Shale Well Control: Drilling and Tripping in Unconventional Oil and Gas Plays," by K. Ridley, SPE, M. Jurgens, SPE, R.J. Billa, SPE, and J.F. Mota, SPE, Shell, prepared for the 2013 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 28-30 January. The paper has not been peer reviewed.
In late 2010, Shell began an Eagle Ford appraisal program in the Piloncillo Ranch lease in south Texas. These wells are 8,500- to 9,500-ft-true-vertical-depth (TVD) horizontals, with an average total depth of 14,500-ft measured depth (MD). Initially, underbalanced-drilling techniques were used to drill the formation. As more wells were drilled, completion fracturing of offset wells began to cause well-control problems as induced fractures were encountered in horizontal sections during drilling. The authors describe the development of well-control techniques that allowed successful drilling operations.
The original pore-pressure concept drove the field to a basic two-string casing design. The wells have 9?-in. surface casing and 5½-in. production casing. The surface-casing point was designed to be set between 3,000- and 3,500-ft TVD in the Midway shale below the base of the freshwater aquifer, which varies between 2,000- and 2,800-ft TVD. The fracture strength at this point was found to be 17 lbm/gal equivalent mud weight (EMW), which was considered to be sufficient for kick tolerance through the openhole interval to total depth (TD) in the Eagle Ford. The next hole section is then drilled out of the surface shoe to the kickoff point in the Austin chalk and landed in the upper Eagle Ford, where a 5,000-ft lateral section is drilled. The bottomhole assemblies (BHAs) were optimized until one run was possible from drilling out the surface shoe to TD of the well. The fracture strength of the surface shoe, along with the assumed pore pressure of 12.5 lbm/gal EMW in the Eagle Ford, allowed for a two-string design.
This initial appraisal phase consisted of single-well pads with 5,000-ft laterals along a preferred azimuth. With further field development, the plan was set with multiwell pads in order to minimize the footprint and reduce undeveloped space in the reservoir (Fig. 1).
Drilling—Phase 1: Initial Wells
The first wells were drilled with a mud weight (MW) of 11.0 lbm/gal and exhibited few well-control challenges. No flow was observed while making connections or when performing flow checks at TD, and minimal background gas while drilling and at bottoms-up upon reaching TD was common. There was no flare during drilling, but the flare at bottoms-up at TD averaged between 10 and 20 ft. Previous experience in the Eagle Ford and other tight gas plays showed this level of gas to be manageable with a conventional rotating control device and a mud/gas separator. Some losses were encountered during the initial 5½-in.- production-casing cement jobs with a two-slurry design of top of cement at surface and a 12.7-lbm/gal lead and 16.4-lbm/gal tail. This was attributed to formation weakness in the Olmos sand, which occurred from 5,300- to 6,700-ft TVD. Equivalent-circulating- density simulations established this formation as a potential weak point, with an estimated fracture strength between 13- and 14-lbm/gal EMW across the field.
In late 2010, Shell began an Eagle Ford appraisal program in the Piloncillo Ranch lease in south Texas. These wells are 8,500- to 9,500-ft-true-vertical-depth (TVD) horizontals, with an average total depth of 14,500‑ft measured depth (MD). Initially, underbalanced-drilling techniques were used to drill the formation. As more wells were drilled, completion fracturing of offset wells began to cause well-control problems as induced fractures were encountered in horizontal sections during drilling. The authors describe the development of well-control techniques that allowed successful drilling operations.
Abstract The naturally fractured Buda formation, which underlies the Eagle Ford shale play across central and south Texas, is experiencing resurgence in exploration and production activity as a result of improvements in horizontal and underbalanced drilling techniques. Formed during the Cretaceous period, the Buda formation was produced from vertical wells for decades, leaving aside the potential of crossing all the vertical fractures and associated recoverable hydrocarbons. However, many fractures in the Buda formation are underpressured because not filled with hydrocarbons from the overlying Eagle Ford formation. The application of Underbalanced Drilling in horizontals wells to drill Buda wells is today showing excellent results. The underpressured nature of some fractures in the Buda dictates that wells be drilled underbalanced; drilling the formation conventionally typically results in issues such as considerable circulation losses and then associated kicks when drilling through depleted and filled fractures. In certain areas, the Buda formation also presents the challenge of hydrogen sulfide gas (H2S), which poses environmental and safety issues. In some cases, the Buda's fracture systems may be vertically extensive enough to establish hydraulic continuity with underlying formations, a situation that could result in extraneous water production. This paper examines a case study employing Underbalanced Drilling (UBD) techniques to drill a well in the Buda Limestone formation. Before embarking on the project, the operator conducted a six-county assessment of the Buda, comparing wells that were drilled using a conventional mud system with wells that were drilled using underbalanced drilling techniques. A significant concern with drilling the wells conventionally was that the weight of the drilling fluid column would create pressure against the 5.0 pounds per gallon (ppg) or less from sub pressured fractures from Buda formation, which could result in severe to total loss of drilling mud. Even drilling this formation with freshwater applies 8.33 ppg of pressure for a column of fluid. The study revealed the UBD wells mitigated the loss of drilling fluid and allowed the producing section to be drilled successfully to total depth. Using UBD techniques also yielded significant improvements in production through its ability to prevent drilling mud and chemical additives from invading the drilled formation. With the UBD approach, the operator was able to drill the production section of eleven wells (at today) to TD (Target Depth) using an open-hole completion and effectively control low-pressure zones. The approach resulted in benefits such as reducing rig time and nonproductive time (NPT), incurring minimal fluid losses, obtaining early production of crude while drilling, and characterizing the reservoir for future developments. As the industry continually strives to meet the ever-growing demand for hydrocarbons worldwide, new technologies are seeing expanded application not only in emerging, but in mature conventional plays with untapped potential. UBD technology was combined with advanced MWD tools, mechanically operated wellbore isolation devices, multibore wellhead system and efficient four phase separation. This has provided the operators an opportunity to have a second look at the Buda formation and overcome steep challenges to produce wells more efficiently and economically than before.
Abstract Unconventional gas resource plays continue to have a significant impact on natural gas production in the US due to recent technological advances and higher demand for gas. In the US, 22% of the total energy consumed comes from natural gas. The US domestic production of natural gas is around 85% of the demand; currently about half of that comes from unconventional resources. Primary unconventional sources are tight gas, shale gas, and coalbed methane (CBM). Tight gas, shale gas and CBM production accounts for approximately 28%, 14% and 8%, respectively, of total US gas production. Total US production for 2010 is 21.57 tcf. Achieving sustainable production from unconventional gas resources requires reaching extended areas of the reservoir and performing effective hydraulic fracturing, with its associated technologies, to help reduce risk and increase the success rate. Compared to production in vertical wells, the production of tight gas and shale gas in horizontal wells has increased significantly due to the ability to reach extended areas as a result of enhanced drilling technologies. Horizontal wells represent a large portion of the well count in US plays, with rigs for horizontal wells increasing from 10% to 58% of the total drilling rigs within the last 6 years (2005–2010). This increase in activity was achieved through careful engineering designs and use of new technologies to address the complexities involved in planning, drilling, completing, and stimulating horizontal wells. In recent years, microseismic hydraulic fracture monitoring (HFM) has become a key technology in understanding the propagation mechanism of the created fractures during stimulation treatments. The paper discusses horizontal well drilling activity in a south Texas play over a 6-year period beginning in 2005. Drilling activity trends and completion practices in some tight gas and shale gas formations in the south Texas basin are highlighted. Additionally, the paper takes a look at the application of microseismic HFM to increase the success rate of horizontal wells in the south Texas basin by reducing some of the completion risks and challenges. Finally, the paper discusses ways to improve the overall completion and stimulation designs of horizontal wells in unconventional gas formations to ensure efficient recovery.
Abstract Challenges associated with Utica and Marcellus shale well integrity and safety necessities further study in order to have an effective and economic drilling operations. Objectives of this comparative study are to evaluate the impact of unscheduled well control events on wellbore integrity, as well as the influence of poor drilling practices that trigger well control emergencies in shale gas wells. A realistic multiphase simulator is used to evaluate well control unexpected scenarios in Utica and Marcellus shales. Changing operational parameters such as wellbore profile, well control method, drilling fluid type and circulation rate in Marcellus and Utica horizontal wells are investigated. Further, this research studied the impact of influx type, size and intensity on well integrity. Behavior of dry gas, rich condensate and black oil influxes are compared in extended lateral wells. The impact of free gas migration in inclined downward laterals drilled with water based mud is compared to the influence of gas solubility in inclined upward wells drilled using synthetic oil based mud. Preliminary results show that deeper, over-pressurized Utica shale presents more challenges compared to Marcellus shale wells. When oil based muds are used additional challenges are presented since the surface pressures and volumes are not representative of the bottom-hole conditions. Dissolved gas in oil is liberated at the bubble point pressure complicating surface kick handling procedures. Gas influx migrates and reaches surface much quicker in water based muds and inclined downward laterals. Higher the influx circulation rate, size and intensity, higher the resultant pressures and volumes and higher the risk of exceeding casing shoe fracture pressure and risking well integrity. Drilling fluid type, properties and flow characteristics are critical for well integrity. Early detection is a key factor in minimizing kick size and properly contain pressures without violating safety and environment regulations and reduces the blowout associated risks. Accordingly, well integrity is verified by monitoring surface choke, casing shoe and constant bottomhole pressures throughout the entire well control operations.