HORIZONAL DRILLING RETAINS STEADY SHARE OF U.S. ACTIVITY

Aug. 10, 1992
A. D. Koen Gulf Coast News Editor After peaking in late 1990 and early 1991, U.S. horizontal drilling activity began a steady slide that carried through first half 1992. But despite higher drilling and completion costs and significant technological challenges, U.S. horizontal action has held its share of activity in a declining domestic oil and gas industry.
A. D. Koen
Gulf Coast News Editor

After peaking in late 1990 and early 1991, U.S. horizontal drilling activity began a steady slide that carried through first half 1992.

But despite higher drilling and completion costs and significant technological challenges, U.S. horizontal action has held its share of activity in a declining domestic oil and gas industry.

Before 1988, only 66 horizontal wells had been permitted in nine states and 48 horizontal completions filed in six states, according to Petroleum Information Corp. (PI), Denver. PI U.S. summaries in late June listed 3,440 applications filed for permits to drill horizontal wells in 25 states and the Gulf of Mexico. In completion summaries, PI counted 2,708 U.S. horizontal wells in the gulf and 20 states.

On a quarterly basis, more than 8% of the active U.S. rotary rigs counted since first quarter 1991 by Baker Hughes Inc., Houston, have been drilling horizontal wells. When the Baker Hughes rig count dropped to a modern day low of 596 during the week of June 12, nearly 10% of all U.S. rigs-56-were working on horizontal wells.

The Cretaceous Austin chalk play of Southeast Texas remains the focal point of U.S. horizontal drilling interest. But more U.S. operators are trying horizontal wells, mostly in fractured reservoirs, defining economic and technological limits well by well.

Although more than 91% of U.S. horizontal locations permitted are for development wells, PI in the year ended last July 1 counted 51 applications to drill horizontal wildcats.

Through innovation and sheer repetition, producers and contractors are developing better drilling techniques, lowering costs, improving safety and wellsite efficiency, and asking more of horizontal technology. Even though activity has waned, horizontal service and equipment companies have responded with continuing refinements.

Although success rates are high, the more capable companies become, the more opportunities and room for progress they see.

Major and independent operators generally are carving niches in U.S. horizontal plays by carefully selecting prospects, methodically planning wellsite procedures, and correlating geological characteristics and well data for clues to results.

HORIZONTAL HOTSPOTS

Texas continues to dominate U.S. horizontal drilling activity. PI data show Texas has accounted for 2,776 (80.7%) of U.S. horizontal wells permitted and 2,250 (83.1%) of U.S. horizontal completions.

North Dakota is the second most active state, with 246 horizontal drilling permits issued and 183 completions filed.

The Texas Railroad Commission has issued permits for horizontal wells in 78 counties. But the Austin chalk is by far the state's-and the nation's-biggest horizontal play.

In the past year ending in June, Texas operators filed drilling permits for 614 Austin chalk wells, PI reported. Through March 1992, completions filed for horizontal chalk wells in the previous 12 months totaled 826.

Pearsall and Gidding fields of Texas are the two leading U.S. horizontal plays, thanks to chalk drilling activity. Texas counties fill PI's top 10 list of leading U.S. horizontal counties based on drilling permit filings and hold the top nine positions on the top 10 list based on completions.

The nation's second most active horizontal target is the Cretaceous Buda, also in Texas and almost directly under the chalk. PI's count shows operators during the year ended July 1 filed 118 permits to drill horizontal Buda wells and in the year ending Apr. 1 filed 42 Buda horizontal completions.

Mississippian Bakken in North Dakota and eastern Montana in the Williston basin is the third most active U.S. horizontal formation. PI counted 33 Bakken drilling permits during the year ending July 1 and 42 Bakken completions in the year ending Apr. 1.

Upper Cretaceous Niobrara is close behind Bakken as the next most active U.S. horizontal formation. Drilling permit filings for horizontal Niobrara wells during the year ending July 1 totaled 31, and 18 Niobrara completions were filed in the year ending Apr. 1, PI said.

The top four formations on PI's list of drilling permit filings accounted for 78.7% of the U.S. total during the year ended July 1. Of 1,036 U.S. horizontal well completions filed during the year ended Apr. 1, more than 87% were for wells in the four busiest target formations.

Edwin Marker, who produces PI's horizontal drilling report for the U.S. northern region, said measured footage for horizontal wells on the company's list of U.S. completions for the year ended Apr. 1 averaged 9,237 ft/well.

OTHER REGIONS

Among the nation's most noteworthy horizontal plays outside Texas, Marker cited activity spreading across Oklahoma, where only one horizontal well was reported completed before 1990.

"There are so many formations there conclusive to horizontal drilling that the potential for infill and exploration drilling seems to be great," he said.

In addition, Marker lists the Pennsylvanian Cane Creek play along the San Juan County-Grant County line in Utah's Paradox basin as an area with good horizontal potential.

"There's complex geology out there, but very few wells have been drilled," he said. "That looks like a wide open area."

Marker said Bakken horizontal activity appears to be leveling off at a steady rate of development, with permits and completions not varying much from month to month.

"The San Juan basin is an up and coming area," he said. "We've seen a good increase in activity there for the past 6-8 months.

"Again, a number of formations in the San Juan basin are good horizontal targets."

UPRC NO. 1

In the past year, Union Pacific Resources Co. (UPRC), Fort Worth, has emerged as the nation's busiest horizontal operator. It is one of a handful of companies to try horizontal wells in several states.

UPRC in mid-July had 31 rigs drilling horizontal wells in the U.S., including 28 in the Austin chalk area. For the week of July 17, Baker Hughes counted 56 rigs drilling horizontal wells nationwide among a total U.S. active rotary rig count of 689.

Most of UPRC's Austin chalk activity is in Giddings field, and most of that is in Fayette and Brazos counties. The company has not been a big player in Pearsall field at the southern end of the chalk trend but had one rig running there in mid-July.

The company recently completed its first chalk well on the eastern end of the trend in Vernon Parish, La.

In the year ended last June, PI reported UPRC filed permits to drill horizontal wells at 268 locations, tops in the U.S. And for the year ended last March, UPRC filed completions for 162 horizontal wells with combined measured footage totaling almost 2 million ft.

Nationwide summaries compiled by PI covering the same periods totaled 1,001 horizontal drilling permits filed and 1,026 horizontal completions with combined footage of about 9.5 million ft.

UPRC has drilled about 350 horizontal Austin chalk wells. About 335 were producing at mid-July. The company's net production in June from chalk wells averaged 34,000 b/d of oil, 103.5 MMcfd of gas, and 5,900 b/d of plant liquids.

John Vering, UPRC Austin chalk project manager, said the company continues to reduce costs as it moves along the horizontal learning curve.

Vering said UPRC's drilling and completions costs total less than $1 million/well in Fayette County.

"One year ago, we were spending $1.2-1.4 million for a horizontal well," he said.

OTHER UPRC ACTIVITY

Bill Lancaster, UPRC exploration operations manager, said the company also is expanding its horizontal drilling program outside the Austin chalk trend.

The company in the past 18 months has drilled about 15 wells to Cretaceous Buda-Georgetown strata and plans another half dozen to evaluate the formations' potential. Buda-Georgetown is a micritic limestone as thick as 100 ft each.

"The reserves are not quite as big as the Austin chalk," Lancaster said. "So when the chalk depletes, we will low side those horizontal wells using the vertical wellbores for about half the cost of a grassroots horizontal chalk well."

When its exploration program is complete, UPRC will have horizontal Buda-Georgetown wells in Fayette, Lee, Washington, Burleson, Brazos, and Robertson counties, Tex. The company has not yet firmed up exploratory plans beyond those counties.

Carbonate formations in East Texas also could be in the UPRC picture, "but I'd rather not name them at the moment," Lancaster said.

UPRC also has drilled horizontal wells outside Texas.

The company completed three Mississippian horizontal wells in the Sooner Trend near Enid, Okla. The most recent, a reentry of a vertical well, reached total depth in mid-July. UPRC's economic assessment of the play is pending.

UPRC has 10 productive wells in the Silo field area of Wyoming and plans to keep one rig busy there for the foreseeable future. Silo field is part of the Niobrara horizontal play stretching across the Denver-julesburg, Hanna, and Sand Wash basins.

UPRC has drilled about half a dozen Niobrara wildcats outside the Silo area and plans more drilling.

Niobrara is the same age as the Austin chalk and of similar deposition.

"Like the Austin chalk, we also see multiple reservoirs in Silo field," Lancaster said.

UPRC plans to drill horizontal wells in the next 12 months in several areas of the Rocky Mountain Overthrust Belt. Wells are planned in Wyoming and Utah to the Jurassic Twin Creek, a large fractured carbonate formation, and to Wyoming's Ordovician Big Horn.

REINING PRODUCTION

UPRC's Lancaster said his company also had early problems in Silo field when it tried to produce the first four or five wells at rates of 800-2,000 b/d, "like we do in the chalk."

With that production scheme, Silo production rates declined from 2,000-3,000 b/d in 2-3 months to only tens of barrels a day.

"That clearly was not an economic play," he said.

UPRC theorized Silo production declined because high production rates created pressure drawdown that closed the fractures or the gas was produced out of solution too quickly. So the company has been holding production rates to about 10 bbl/hr.

"And our best Silo well now has produced at that rate for the past 18 months," Lancaster said. "There has been very little decline."

Cutting upfront production rates changed well economics. But restraining production allows UPRC to increase ultimate recovery.

"How you produce horizontal wells has great bearing from play to play," Lancaster said.

UPRC believes that the better horizontal technology is understood the more applications will be economic.

TRIAL AND ERROR

Gordon Talk, western division manager, Torch Energy Advisors Inc., Houston, said many insights into optimizing horizontal technology are learned by trial and error.

"The only way to learn is to go out and drill," Talk said.

Torch has participated as a partner in many UPRC operated wells in the Austin chalk. In 1990, the company acquired a 3,000 acre leasehold in Fayette County and to date has drilled 17 of its own horizontal chalk wells.

Torch's most recent chalk well, its 18th, is the first to tap a pay zone above an ash marker about 35-40 ft above the bottom of the chalk. Torch uses the marker to help identify a chalk pay zone at 11,200-500 ft.

The company plans to drill 12-15 horizontal Giddings wells this year. It also plans a horizontal well on Ship Shoal 291 field in the Gulf of Mexico.

Talk said Torch horizontal well drilling costs during the past 2 years have decreased from about $2 million/well to $1.4-1.5 million/well.

Talk has trimmed Torch's drilling costs and increased efficiency, while maintaining high safety standards. He attributes much of the gain to the experience of Torch's crews.

"Repetition is the greatest thing to continue upgrading the quality of drilling personnel and service companies," he said. "We try to keep the same people together on each well, including the same mud engineer and logger and the same drilling contractor and tool pushers."

INCREASING CONTROL

Talk said he quickly learned that by managing time on various tasks, he can slightly reduce drilling time but greatly increase his control of the drilling process.

At first, when a Torch crew cut a vertical chalk fracture and logged a kick, Talk stopped drilling to kill the well.

"When I first started, I wanted to make sure the operation was safe," he explained. "Sometimes after I'd kill the well, I'd drill ahead another foot and I'd have to stop and kill it again."

Finally, Talk realized that until he drilled out of a fracture he might have to stop to kill the well every foot.

"So I began trying to maintain a pressure I could control and keep on drilling," he said. "Now I don't kill the well anymore. If I can keep the back pressure below 500 psi, I'll drill ahead."

One way Talk has maintained safety while reducing drilling time is by keeping three parallel mud systems on standby at horizontal wellsites. All three systems are integrated into a manifold so a worker can change mud weights from 10.5 lb to 11 lb or 12.212.8 lb by opening one valve and closing another.

"Training is essential for drilling hands and consultants and everybody else because if you pump the wrong fluid down the hole you're inviting disaster," he said.

Talk said Torch drills with clear fluid after setting casing to the Austin chalk for easier cleanup of horizontal sections and more complete recovery. But drilling with clear fluids means downhole pressures and gas are transmitted to the surface faster than when drilling with weighted mud.

"When you take a kick, you've got about 15-30 min and it's going to be at surface," he said. "If we were drilling with a heavier mud, it might take 1-1/2 hr to get to the surface."

When he hits a vertical chalk fracture, Talk knows 10.5 lb fluid won't control the pressure. But by switching to a heavier mud in a matter of a few seconds, he lessens the risks and is able to continue drilling.

COST EFFECTIVE ADVANCES

Talk acknowledged that a lot of progress has been made in the past 3 years. But he said Torch hopes service companies have enough room in their budgets for research and development to help solve some of the remaining problems.

Even when technological advances occur, Talk said, high costs sometimes prevent horizontal well operators from using them. An example: blowout prevention systems.

"We have rotating annular blowout preventers now," he said, "but I don't use them because they are very expensive. Instead, I've gone to a two BOP system and a power swivel."

Talk said he generally manages to drill more than one well with each BOP before having to change out rubber seals on the rotor.

"It's a lot simpler to do that than to try to rig up the swivel or use a relating BOP," he said. "Also, I can run a wireline and use my steering tool because MWD will not work in the high temperatures."

Talk said Torch soon learned temperatures of the chalk on its locations range upward to 300 F., straining the capabilities of downhole equipment.

Tim Probert, president of Baker Hughes subsidiary Eastman Teleco, said there is a lot for companies developing horizontal technology to build on. He said horizontal tools companies continue to refine equipment.

At last count, Eastman Teleco had provided downhole tools for horizontal sections on more than 1,000 U.S. wells.

Among the most important advances, Probert includes adjustable stabilization systems and closed loop drilling systems that provide a more complete downhole intelligence package.

"That will further improve the economics for the customer," Probert said.

COSTS AND TECHNOLOGY

Tom Johnston, president and chief operating officer of BecField Horizontal Drilling Services Co., Houston, said a combination of better drilling contractors and better downhole tools has radically cut the cost of drilling horizontal wells.

Johnston said an internal analysis showed "the client's cost today for our service to drill a foot of hole is about one third the cost 4 years ago."

The lower cost takes into consideration faster drilling times and lower contractor rates. On average, BecField's service accounts for about 15-20% of the cost of a $1 million horizontal well, Johnston estimated.

BecField provides all downhole equipment required to connect onto the end of conventional drillpipe and use a conventional rig to take a well from vertical to horizontal.

In the past 4 years, BecField has worked on more than 450 horizontal wells - mostly in the Austin chalk - including about 300 slim hole horizontal reentries. With 10 crews operating in mid-July, BecField was working on about one in six of all horizontal wells being drilled in the U.S.

Johnston said company crews have worked in every major U.S. horizontal play, including the Rockies, Oklahoma, New Mexico, and Louisiana.

"We've had some very successful deep Bakken reentry wells in North Dakota and some shallower Austin chalk wells," Johnston said.

BecField has seen improvement in the performance of downhole motors, reliability of MWD guidance systems, and bit performance. All those improvements allow operators to stay on bottom longer and drill farther between trips, a key to efficiently drilling a horizontal well.

Yet Johnston said tool companies need to continue increasing mean times between failures on motors, MWD capabilities, and bits.

"We need to get that up to more than 200 hr," he said.

Johnston estimated the mean time between tool failures has increased to slightly more than 100 hr from about 40 hr 4 years ago.

"Before the horizontal activity really began to take off, most drilling runs with motors were 40 hr at the most," he said. "So 40 hr was a very acceptable number at that time.

"Now, we drill much longer than 40 hr and we need to be capable of staving in the hole at least 100 hr to be competitive with other service companies," Johnston said. "Tool designers need to highgrade components until they find ones that will withstand the environment longer."

UPRC's Lancaster said there is a persistent need for better horizontal slim hole logging tools.

Lancaster said UPRC can redrill and log old vertical wells very comfortably because casing on those wells typically is 5 1/2-7 in.

On a grassroots horizontal well, UPRC sets 7 in. casing and uses conventionally sized logging tools. But when drilling out of 5 1/2 in. casing on an old vertical wellbore, an operator must use about a 4 in. bit.

"That is too small for conventional logging tools," he said.

Lancaster acknowledged that some horizontal services companies have built prototypes. "But they're hard to come by and they're expensive."

COMING ADVANCES

Eastman Teleco's Probert said areas in which horizontal well technology has been developed and is continuing to grow quite rapidly include:

  • Geosteering, using formation evaluation capabilities of MWD in combination with horizontal tools to keep the bore hole in the most productive portion of the pay zone.

    "You get some very interesting phenomena when you pass close to bed boundaries while using formation evaluation tools," he said. "That enables you to provide some steering during the course of drilling the well."

  • Increasing use of slim hole technology in horizontal drilling.

    "We're starting to see more reductions in hole size, and that will require reducing sizes of tubulars and other consumables," he said. "Many companies - Shell, BP, Amoco, ARCO have a lot of interest in drilling slim holes because the cost is substantially lower.

    "That could become a major issue internationally."

  • Closed loop drilling, a system fully integrated between MWD and the balance of the bottomhole assembly to establish and maintain desired trajectory.

    "That's not something we're going to see this year or next year, but it's certainly a priority with us in some of our technology," he said.

    Probert said short radius reentry wells are another particularly interesting growth sector for horizontal technology.

    "We're starting to see the fruition of 2-3 years of development work in that field really starting to pay off," he said. "That's attractive because it is supportive of existing wells and production, almost like an enhanced recovery technique as opposed to a new field technique."

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