EQT Production has implemented a new technique for drilling horizontal wells in the hard formations of the Appalachian Basin.Air percussion drilling has been adopted for use horizontally in the Berea sandstone, a hard and abrasive sandstone reservoir that had been traditionally drilled with roller cone bits. The evolution of the technology started with a packed-hole assembly that was trialed on three wells using stabilizer placement to provide directional control in the horizontal. The results were promising as penetration rates increased, but many trips were required to keep the wellbore in the desired target zone. To improve directional control, a percussion BHA with a bent housing positive displacement motor (PDM) was implemented. The introduction of the positive displacement motor with the air hammer produced the same penetration rates seen in the packed-hole assembly while providing the directional control needed. Since mid 2009, the PDM percussion assembly has become the standard practice for drilling Berea horizontal wells, replacing the roller cone BHA. Through June 2010, over 40 wells have been drilled using the assembly. The lateral portion for a majority of the wells is now drilled in one run, reducing total drilling time from 22 to 13 days, dry hole costs by over one half and total well costs by about one third.
Summary Petro-Hunt Corp. used a unique horizontal-well design to optimize development of an irregularly shaped lease in the Austin Chalk formation in Texas. Two medium-radius horizontal bores were drilled in opposite directions from one vertical hole to maximize horizontal displacement in the lease. Underbalanced drilling techniques were used to prevent formation damage. The well design resulted in a significant cost savings per horizontal foot compared with 24 offset wells that the operator drilled. This paper reviews well planning and drilling and emphasizes techniques used to intersect thin horizontal targets and to initiate the second horizontal bore. Production results and drilling economics are discussed briefly, and ideas on future dual-horizontal-well applications are presented. Introduction Austin Chalk Formation. The literature presents1–3 many descriptions of the Austin Chalk formation in Texas. For this paper, the formation is characterized as a dense, amorphous, Cretaceous limestone often found to contain intebedded and sometimes marly shale streaks. Fig. 1 shows a trend map of this oil-bearing formation. In the past, the low matrix porosity and low permeability of the Austin Chalk formation limited the economical development of its hydrocarbons to those areas where a vertical well had a reasonably good chance of penetrating a naturally occurring vertical fracture system. These fracture systems are most extensive when associated with local faults or anticlines.2 The presence of vertical fractures in this otherwise tight formation makes it ideal for horizontal drilling. Since 1985, drilling of horizontal wells has become increasingly more popular than vertical wells for improving the success rate in previously developed areas of the Austin Chalk formation. Horizontal drilling also is used to explore areas considered too risky for vertical wells because of the sparseness of the local fracture systems. Continued improvements in horizontal drilling technology caused Austin Chalk drilling to reach "boom" levels in early 1990. Although some horizontal wells drilled in the Austin Chalk have been completed with slotted liners or casing, the openhole completion method is preferred. The high mechanical integrity of the Austin Chalk is conducive to openhole completions. Advantages to this method include (1) low initial costs, (2) little potential for mechanical problems, (3) more options than other methods for recompletion or remedial work, and (4) minimal flow restriction.4 The Pearsall Field, located 70 miles southwest of San Antonio, supported prolific levels of horizontal drilling activity in 1990–91. Pearsall Partners (Petro-Hunt Corp. of Dallas is managing partner) participated in the drilling of 25 horizontal wells in this field during 1990. The subject of this paper, McDermand Well No. 1, was the 15th well in this series. McDermand Well No. 1. Pearsall Partners operated McDermand Well No. 1; other working interest owners were GLG Energy LP, Austin, and WCS Oil & Gas Corp., Dallas. Located in Frio County, the well is in the southern one-half of the Pearsall field. The targeted pay zone was Interval B1 of the Austin Chalk formation. Interval B1 is a particularly clean, brittle, limestone interval likely to contain microfracture systems. Interval B1 was expected to lay ˜130 ft below the top of the Austin Chalk formation. Penetration of a gas cap or a water boundary was not anticipated. The geologist assigned a horizontal target tolerance of ±10 ft true vertical depth (TVD) to the prognosis depth. An openhole completion would be used on the well. Two primary factors that influenced well planning were lease geometry and fracture orientation. Fig. 2 depicts the lease geometry. The predominant fracture orientation in that part of the field paralleled the north 40° east formation strike. Offset-well data indicated local formation dip to be 1.6° to the southeast. The following criteria were established as necessary to optimize lease development.Maximize horizontal length.Drill perpendicular to the fracture orientation.Allow adequate directional control to keep the wellbore within the lease "hard" lines.Minimize drilling, completion, and production costs. Minimizing costs could be accomplished best by drilling only one well on the lease. Furthermore, field rules stipulated that a second well drilled on the lease would have to be at least 1,200 ft from the original well at all points in the pay zone. Maximizing horizontal length while drilling perpendicular to the fracture orientation would require a northwest-southeast horizontal-well orientation and also would require drilling into the narrow "panhandle" in the northwest lease quadrant. This plan would allow for up to 5,700 ft of horizontal displacement. Two concerns were raised with this plan.Was it reasonable to expect to achieve 5,700 ft of displacement without encountering significant drilling problems? Then, the most displacement ever achieved in the Austin Chalk formation was ˜4,600 ft.Could the well azimuth be controlled adequately, without excessive orientation, to permit passage through the narrow panhandle neck and to keep the wellbore from walking out of the legal lease boundaries? An unusual well plan evolved to address both concerns. The surface location would be placed near the narrow panhandle neck, and a vertical hole would be drilled down to the kickoff point. From there, two opposing horizontal bores, "wings," would be drilled. One wing would be drilled downdip, perpendicular to the fracture orientation, to the southeast. The second wing would be drilled nearly opposite to the northwest. (Lease geometry would prevent us from drilling the northwest wing exactly perpendicular to the fracture orientation.) It was suggested that this well plan also might produce an additional benefit that had not been considered previously. Producing through two intermediate-length horizontal wings instead of one long bore might result in lower bottomhole flowing pressures and higher production rates. Ref. 5 presents a mathematical investigation of this theory. Well Planning Drilling Rig. A triple-derrick drilling rig, rated to 9,000 ft with 4 1/2-in. drillpipe, was selected. The rig was fitted with a 1,000-HP drawworks and two 800-HP triplex pumps. Austin Chalk Formation. The literature presents1–3 many descriptions of the Austin Chalk formation in Texas. For this paper, the formation is characterized as a dense, amorphous, Cretaceous limestone often found to contain intebedded and sometimes marly shale streaks. Fig. 1 shows a trend map of this oil-bearing formation. In the past, the low matrix porosity and low permeability of the Austin Chalk formation limited the economical development of its hydrocarbons to those areas where a vertical well had a reasonably good chance of penetrating a naturally occurring vertical fracture system. These fracture systems are most extensive when associated with local faults or anticlines.2 The presence of vertical fractures in this otherwise tight formation makes it ideal for horizontal drilling. Since 1985, drilling of horizontal wells has become increasingly more popular than vertical wells for improving the success rate in previously developed areas of the Austin Chalk formation. Horizontal drilling also is used to explore areas considered too risky for vertical wells because of the sparseness of the local fracture systems. Continued improvements in horizontal drilling technology caused Austin Chalk drilling to reach "boom" levels in early 1990. Although some horizontal wells drilled in the Austin Chalk have been completed with slotted liners or casing, the openhole completion method is preferred. The high mechanical integrity of the Austin Chalk is conducive to openhole completions. Advantages to this method include (1) low initial costs, (2) little potential for mechanical problems, (3) more options than other methods for recompletion or remedial work, and (4) minimal flow restriction.4 The Pearsall Field, located 70 miles southwest of San Antonio, supported prolific levels of horizontal drilling activity in 1990–91. Pearsall Partners (Petro-Hunt Corp. of Dallas is managing partner) participated in the drilling of 25 horizontal wells in this field during 1990. The subject of this paper, McDermand Well No. 1, was the 15th well in this series. McDermand Well No. 1. Pearsall Partners operated McDermand Well No. 1; other working interest owners were GLG Energy LP, Austin, and WCS Oil & Gas Corp., Dallas. Located in Frio County, the well is in the southern one-half of the Pearsall field. The targeted pay zone was Interval B1 of the Austin Chalk formation. Interval B1 is a particularly clean, brittle, limestone interval likely to contain microfracture systems. Interval B1 was expected to lay ˜130 ft below the top of the Austin Chalk formation. Penetration of a gas cap or a water boundary was not anticipated. The geologist assigned a horizontal target tolerance of ±10 ft true vertical depth (TVD) to the prognosis depth. An openhole completion would be used on the well. Two primary factors that influenced well planning were lease geometry and fracture orientation. Fig. 2 depicts the lease geometry. The predominant fracture orientation in that part of the field paralleled the north 40° east formation strike. Offset-well data indicated local formation dip to be 1.6° to the southeast. The following criteria were established as necessary to optimize lease development.Maximize horizontal length.Drill perpendicular to the fracture orientation.Allow adequate directional control to keep the wellbore within the lease "hard" lines.Minimize drilling, completion, and production costs. Minimizing costs could be accomplished best by drilling only one well on the lease. Furthermore, field rules stipulated that a second well drilled on the lease would have to be at least 1,200 ft from the original well at all points in the pay zone. Maximizing horizontal length while drilling perpendicular to the fracture orientation would require a northwest-southeast horizontal-well orientation and also would require drilling into the narrow "panhandle" in the northwest lease quadrant. This plan would allow for up to 5,700 ft of horizontal displacement. Two concerns were raised with this plan.Was it reasonable to expect to achieve 5,700 ft of displacement without encountering significant drilling problems? Then, the most displacement ever achieved in the Austin Chalk formation was ˜4,600 ft.Could the well azimuth be controlled adequately, without excessive orientation, to permit passage through the narrow panhandle neck and to keep the wellbore from walking out of the legal lease boundaries? An unusual well plan evolved to address both concerns. The surface location would be placed near the narrow panhandle neck, and a vertical hole would be drilled down to the kickoff point. From there, two opposing horizontal bores, "wings," would be drilled. One wing would be drilled downdip, perpendicular to the fracture orientation, to the southeast. The second wing would be drilled nearly opposite to the northwest. (Lease geometry would prevent us from drilling the northwest wing exactly perpendicular to the fracture orientation.) It was suggested that this well plan also might produce an additional benefit that had not been considered previously. Producing through two intermediate-length horizontal wings instead of one long bore might result in lower bottomhole flowing pressures and higher production rates. Ref. 5 presents a mathematical investigation of this theory. Drilling Rig. A triple-derrick drilling rig, rated to 9,000 ft with 4 1/2-in. drillpipe, was selected. The rig was fitted with a 1,000-HP drawworks and two 800-HP triplex pumps.
The Mereenie development project is targeting oil and evaluating natural gas reservoirs in the lightly drilled Amadeus Basin. In 2012, an operating company started searching for methods to improve rate of penetration (ROP) drilling the 8¾″ vertical hole section through the difficult Stairway and Pacoota sandstone formations. The lithology consists of very abrasive and hard siltstone/sandstone with UCS up to over 30,000 psi. The hole section starts at 500 m and generally requires 700 m of total wellbore to reach KOP at 1200 m. The section has historically been drilled with PDC and Roller Cone bits with mud as the circulating medium. Both types of BHAs produced unacceptably slow ROP and required multiple trips to reach TD. The operator required a new approach. To accomplish the objective, the operator wanted to switch from mud to underbalanced drilling using an air percussion BHA equipped with a hammer bit. However, an analysis using a well records database showed that only short (10–30m) shallow surface intervals had been drilled in Australia with percussion air hammers mostly in mining applications in the 1980–90's. To increase the chance for early success, the operator wanted to import the latest air hammer tools and drilling techniques from North America. The provider suggested taking lessons learned from the Northeast USA where air hammer drilling plays a major role in developing oil and gas reserves in the region. The two applications are similar with regards to formation characteristics and the drilling team concluded the provider's downhole tool technology, service culture and experience/expertise would be integral to project success. In Q4 2013 the provider drilled the fastest and deepest percussion air hammer run in Australia's Oil and Gas history at 24 m/hr, 700% faster than the previous ROP achieved with PDC or Roller Cone.
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