ALASKAN N. SLOPE FOCUS SHIFTS FROM WILDCATS TO CUTTING PRODUCTION COSTS

North Slope operators are trying to hold the line against declining production with programs hit by lingering uncertainty over crude prices and taxes.

The emphasis has shifted from last year's strong exploratory drilling campaign and high hopes fueled by the Kuvlum discovery (OGJ, May 31, 1993, p. 15) to focus on more cost-efficient recovery of oil from producing fields. On the exploratory scene, the level of activity was low this past winter on the North Slope.

Although Prudhoe Bay remains far out in front as the top producing field in the U.S., a field decline that began in 1989 continues. In the first quarter, the field produced an average 1.12 million b/d including condensate and natural gas liquids, down 8.2% from the same time a year ago. The target for this year is 1,040,000 b/d of total liquids, said Brian E. Davies, BP Exploration (Alaska) Inc.'s senior vice-president, Prudhoe Bay Unit.

Overall, North Slope output declined in the first quarter but at a lower rate than Prudhoe Bay's. During the period, Prudhoe Bay, Kuparuk River, Endicott, Point McIntyre, and Milne Point together produced an average 1.64 million b/d, down 2.4% from last year. The fields are expected to produce an average 1.6 million b/d for all of 1994, Davies said.

Under a shared service agreement with ARCO Alaska Inc., BP is administrative manager for Prudhoe Bay well work. Six rigs are working, split evenly between new wells and sidetracks/workovers.

In Mardi, North Slope field owners canceled plans to add a fourth drilling rig to the three drilling new Prudhoe Bay field wells and suspended development drilling by the one rig each working in Point McIntyre and Kuparuk River fields.

In spite of the rig cancellation, Davies said the well work program is still a very important part of Prudhoe Bay activity.

"On average, it adds about 100,000 b/d to production each year."

Alliances with service companies play a large role. "We think they're working very well," Davies said of about 10 alliances BP has for well service operations that include wire-line work, stimulation, and coiled tubing assignments in Prudhoe Bay field. "We see some significant savings relative to pre-alliance. In 1993, we think we saved about $8 million. In addition, we have seen very significant improvements in safety and environmental measures."

Horizontal wells and coiled tubing are an important part of the Prudhoe mix. Of horizontal drilling, Davies said, "It's no longer an exotic thing. We use it as a routine thing. It's proving to be very useful."

Chris Phillips, BP's operations engineering manager for Prudhoe Bay, said about 600 coiled tubing operations/year are performed at Prudhoe Bay.

PRUDHOE COILED TUBING

"There are two exciting things going on in coiled tubing work right now," Davies noted. One is the use of coiled tubing to drill through the reservoir section with high angle or horizontal hole after the well has been drilled to intermediate depth with a conventional rig.

The other involves use of coiled tubing for well completion. "We're using 3 1/2 in. coiled tubing as a completion string. This requires two big drums of tubing to complete a standard well." Vertical depth of the producing zone is about 9,000 ft. Each of the 16 ft diameter drums has a capacity of about 6,000 ft of 3 1/2 in. coiled tubing. "They've been run in deviated wells out as far as 11,000 ft," Davies said.

"Coiled tubing is right for the North Slope," Phillips said. "Quick to rig up and rig down. Very effective."

BP operates three coiled tubing units in an alliance with Nowcam, a unit of Camco, Houston. ARCO operates three Dowell Schlumberger units in Prudhoe Bay field and another in Kuparuk River field.

The North Slope coiled tubing business has evolved from nonwinterized units in the early 1980s that were running 1 in. coiled tubing subject to excessive fatigue failures and pinhole leaks. Capabilities were limited to fill cleanouts and nitrogen lift, Phillips said.

Coiled tubing currently is available in sizes of 1/2-3 1/2 in., and units are fully winterized for temperatures as low as 50 F., although operations generally are ceased at 35. Coiled tubing life is 500,000 running ft for the comprehensive capabilities now offered.

Routine applications include acid stimulation, setting and removing sand plugs associated with hydraulic fracturing operations, nonrig workovers, gas and water shutoffs with polymers and straddles/leak repairs. Several coiled tubing completions have been performed, and coiled tubing drilling is being deployed.

"The real benefit of placing add with coiled tubing is that less volume is required and it can be accurately placed with minimum exposure of the completion tubing to corrosive fluids," Phillips said.

Nonrig workovers include gas shutoff and water shutoff. "The mid-1980s cost handled by a rig was $1.5 million," Phillips said. "That prompted development of coiled tubing techniques which led to a cost of $500,000. It's currently $130,000."

Coiled tubing straddles are used to repair holes in production tubing caused by corrosion. "Coil inserted inside the tubing prolongs the life of the well, deferring into the future the need for a rig workover," Phillips said.

"Coiled tubing completions are competitive with the initial rig completion, and we have recently completed two 3 1/2 in. coiled tubing completions with several more planned," Phillips said. "However, future recompletions can be performed at a significantly lower cost with coiled tubing and without the need to mobilize a rig. In addition, the capability of running fully spoolable gas lift systems through existing completions has further enhanced the utility of coiled tubing deployed completions."

BP plans to deploy electric submersible pumps on coil completions to minimize future workover costs.

In drilling applications, coiled tubing offers a savings of $1.5 million/sidetrack vs. the cost of using a conventional rig, Phillips said. The use of coiled tubing improves economics of small accumulations and makes multilaterals possible. "There are at least 500 potential candidates in the Prudhoe Bay field for coiled tubing drilling," Phillips added. "This technology will enable targets to be tapped that would otherwise be uneconomic, leading to significant additional recovery."

Technical challenges include size reduction of directional drilling equipment to 3 3/4 in. hole size, orienting directional drilling motors because the coil string can't be rotated, short radius trajectories, and applying weight to the bit. "We are also actively pursuing geosteering to optimize well targets as we are drilling, Phillips added.

"Between us and ARCO, we've got 10 people working on improving coiled tubing technology for the North Slope. The level of effort is going to cause a lot of benefits in coiled tubing."

The ultimate goal, Phillips said, is to go into a well through tubing and sidetrack a horizontal section at a cost less than $500,000 compared with $2.2 million for doing it with a conventional rig.

"Lower cost is not the only benefit," Phillips added. "The ability to drill underbalanced and test the well as it is drilled means that you only have to drill enough hole until you are satisfied with the well rate. Add to this an ability to geosteer wells to improved target characteristics and we will see a revolution in drilling practices."

RAZOR PROJECT

Prudhoe Bay field's major producers, BP, ARCO and Exxon Corp., are winding up a joint company, $8.5 million effort put in place in 1992 to develop a better understanding of reservoir characteristics in the lowest part of the major oil bearing reservoir in Prudhoe Bay field. Basically, that portion of the Permian Ivishak reservoir studied under the Reservoir Analysis Zone 1/Romeo (Razor) project features the reservoir's lowest quality.

Although the lower units in the formation are believed to hold about 2 billion bbl of oil, they were largely bypassed during Prudhoe's early development because of the abundance of more accessible oil in more productive reservoir units. With Prudhoe's relatively easy to recover oil gone, BP/ARCO/Exxon are taking a closer look at the lower zones, which are heavily faulted, invaded by natural gas, show complex mixtures of rock types, and have relatively thin oil pay zones.

"We have a lot of data from wells drilled through but only a small part of oil from that reservoir has been produced," Davies said. Along with core samples and well logs, the Razor team made up of some 25 earth scientists also has had 3D seismic survey data across the whole reservoir plus production histories of wells to assist with the study.

From the data, Davies said the team hopes to develop methodologies to better predict reservoir quality, thus providing geologists and engineers with technical tools to help them produce a greater portion of the reservoir.

"The challenge now is to take those methodologies and apply them," said Davies. "We're cautiously optimistic of the results and hope over the next 12 months we'll see some positive benefits."

1994 SEALIFT

One positive benefit for Prudhoe is partly in place in the form of Gas Handling Expansion No. 2 (GHX-2) and will soon be augmented by modular facilities that will complete construction of the facility.

The 1994 sealift consisting of four 400 ft barges carrying 14 production modules weighing a combined 23,000 tons left the construction site at New Iberia, La., in early May for the 8,000 mile trip to Alaska and is expected to arrive in early August.

The modules will boost North Slope production by expanding gas handling capacity at Prudhoe Bay and allowing waterflooding at nearby Point McIntyre field.

Completion of GHX-2 will increase Prudhoe's fieldwide gas handling capacity to 7.5 bcfd and boost production of oil and natural gas liquids by about 100,000 b/d. Part of the increase was realized with completion of Phase One of GHX-2 late last year.

The shipment apparently will end a 20 year period of constant oil field development and installation of new production facilities requiring 18 sealifts since 1975. To date, 777 production modules costing more than $20 billion and weighing more than 340,000 tons have been barged to North Slope oil fields.

"We don't have another major project under discussion," said ARCO Alaska Pres. H. L. Bilhartz. "Prudhoe Bay development is essentially complete except for the drilling of new wells. This is the last sealift planned for Prudhoe Bay."

Liquids production at Prudhoe Bay is constrained by the ability of field operators to process and reinject associated natural gas. Since 1988, the field's production has declined to 1.1 million b/d from 1.6 million b/d of hydrocarbon liquids. Installation of additional gas handling capacity will temporarily stem the decline in the near term and slow the rate of decline in the years ahead.

The $1.1 billion GHX-2 project will increase ultimate Prudhoe Bay liquids recovery by about 330-450 million bbl. A similar project, GHX-1, was completed in 1990.

Also included on the 1994 sealift is a produced water treatment module for the Lisburne Production Center. Installation of the module will allow waterflooding to maintain rate and recover more oil from Point McIntyre field, which is produced through Lisburne facilities.

Ralph M. Parsons Co., Pasadena, Calif., designed the gas handling facilities. Raytheon Constructors, Denver, designed the Point McIntyre produced water treatment module. Fluor Daniel Inc., Irvine, Calif. fabricated the modules. VECO International, Anchorage, will install them on the North Slope.

As for Kuparuk River field, second biggest U.S. producer, it took a hit in March. On the heels of BP's decision to cut its 1994 capital budget for Kuparuk by 45% operator ARCO said development drilling in the field would be suspended in May and a number of projects would be deferred.

The slowdown could jeopardize hopes of maintaining production rates at about 300,000 b/d through 2000. The field's production peaked in 1992 with a record average of 322,000 b/d. Last year, the average dropped to 315,523 b/d. During first quarter 1994, Kuparuk production averaged 309,726 b/d. Cumulative production from the field stands at 1.1 billion bbl, with an estimated 700 million bbl remaining. The field's major owners are ARCO 55.17% percent and BP 39.19%, with remaining interests owned by Unocal Corp., Mobil Corp., Chevron Corp., and Exxon.

POINT MCINTYRE: BRIGHT SPOT

The bright spot in the North Slope picture is Point McIntyre field, 2 miles north of Prudhoe Bay field. It went on stream in October 1993 and by end of March 1994 had produced a cumulative 16,424,183 bbl of crude and NGL. Production in the first quarter averaged 98,105 b/d and in early May about 100,000 b/d.

"We were delighted," said Andy Simon, ARCO field manager, of Point McIntyre field's strong performance. "We originally thought with the wells we had you could produce about 65,000 b/d based on test data from earlier wells at Point McIntyre."

In the earlier wells, Simon said the mud program had been a mix of drilling fluids, essentially an oil based mud that resulted in some formation damage as a normal part of drilling.

"We thought we could stimulate wells to get up to 80,000 b/d, but we had been doing some lab work, so we shifted to potassium chloride based mud like that used in the Lower 48. We tailored the mud to be friendly to the reservoir rock, which has some clay in it that swells and chokes production. With potassium chloride based mud, it didn't swell the clay.

"It virtually eliminated formation damage and allowed us to come on at rates up to 100,000 b/d. It enabled us to drill wells more cost effectively, eliminate stimulation cost, and maintain a more pristine formation."

Simon does not expect any drop in production from Point McIntyre when development drilling is idled temporarily in July.

"By July, we will essentially have the majority of 160 acre waterflood wells and waterflood patterns set. We will begin waterflooding in July."

The first phase will involve DS-PM 1, an onshore site from which 16 wells have been drilled, including 15 producers and one gas injector. Four of the producing wells will be converted to water injectors. The second phase, starting in July, will involve DS-PM 2 on the West Dock causeway, about 2 miles east of DS-PM 1, where 21 producing wells have been drilled but are not producing because surface facilities are not in place. Six of the DS-PM 2 producing wells will be converted to water injectors. Between the two drillsites there will be a total of 26 producing wells and 10 water injection wells by yearend.

"We will have more production capacity," Simon said, "but the limiting factor will be the Lisburne processing facility. The facility had a design capability when it was built of 100,000 b/d."

The Lisburne facility is operating at rates of about 140,000 b/d, handling about 100,000 b/d from Point McIntyre, 25,000 b/d from Lisburne, and the rest from Niakuk, North Prudhoe Bay, and West Beach developments.

"We will gather more data and hope to push it up to 150,000 b/d as PM 2 comes on in July," Simon said.

Development drilling probably will resume in January, Simon added. "The base plan contemplates about 80 wells for Point McIntyre, including producers and injectors."

Truckable modules necessary to support the projected 80 well development, including manifold modules, separator modules for testing wells and units to handle methanol to prevent freezing, were fabricated in Anchorage by VECO. A subsurface development team of geologists and reservoir engineers from ARCO, BP, and Exxon expects sometime this summer to finish the first phase of a project begun last summer to develop a reservoir simulator for Point McIntyre.

POINT MCINTYRE BACKGROUND

Point McIntyre field was discovered in 1988 by ARCO and partners Exxon and BP. The pay, at a depth of about 9,000 ft, is Cretaceous sandstone equivalent to Kuparuk River field pay. Reserves are estimated at 340 million bbl, making the field one of the largest U.S. discoveries since Endicott field in 1978. An environmental dispute that pitted U.S. Army Corps of Engineers and Environmental Protection Agency against Point McIntyre partners stalled plans to bring the field on production for more than 2 years.

The dispute involved two existing causeways - Prudhoe Bay West and Endicott - from which the partners proposed to develop and produce the field. The Corps and EPA, before the Endicott causeway was dropped as a possible drillsite, contended that the causeways, in spite of 752 feet of breaches, threatened the Arctic char, broad whitefish, and other fish relied upon by commercial fishermen. The companies disagreed, saying that years of monitoring programs costing $20 million showed no effect on the fish populations.

The U.S. Department of Energy in 1990 helped mediate the dispute in an effort to increase U.S. oil output to help make up for lost Iraqi and Kuwaiti oil supplies after the Iraqi invasion in August 1990.

In the settlement, the oil companies agreed to construct additional breaches in the Endicott and West Dock causeways, almost doubling width of channels through which fish might swim. BP in mid-April completed construction of a 600 ft breach and a 700 ft bridge over it on the Endicott causeway. ARCO is in the first phase of construction of a 600 ft breach in the West Dock causeway, consisting of installing pilings on which supports will be located for an 800 ft long bridge. That bridge will be longer than the Endicott bridge in order to protect pipes buried in the causeway. Next year, the causeway will be breached, and the bridge spanning the channel will be installed.

NIAKUK DEVELOPMENT

Another source of new production on the North Slope is Niakuk, which went on line on Apr. 12 with initial production of 15,000 b/d and is expected to peak at 25,000 b/d by mid-1995. Niakuk, an offshore accumulation northeast of Prudhoe Bay, is a new pool discovery in Prudhoe Bay field.

The start-up from five extended reach wells came after years of delays that saw the project transformed from an offshore development requiring a gravel island and causeway to an onshore development using advanced directional drilling technology from a gravel pad on Heald Point. Niakuk contains an estimated 54 million bbl of recoverable oil in Kuparuk River sandstones. A total of 14 wells is planned for the producing area, which BP owns 100%. BP is operating one rig in Niakuk development.

"Niakuk is relatively small by North Slope standards, but it represents the kind of development that is critical to the future of North Slope oil production," said Jack Golden, BP vice-president.

When preliminary, engineering indicated an offshore development with stand alone production facilities would cost more than $250 million, BP engineers redesigned the project to tap the Niakuk reservoir from an onshore location and process the oil through the nearby Lisburne facility instead of its own facilities.

"We had to completely revamp the way we looked at the project if we were going to make it economic to develop," said Terry Obeney, BP's manager for new development in Alaska.

Development costs were projected at $130 million by the time Niakuk construction began last August, but they have since been reduced to $110 million due to a number of improvements, including pipeline design and utilization, drilling performance, and lower gravel costs.

Houston Contracting Co. laid the first segments of Niakuk pipeline earlier this year. A contract is pending with Alaska Petroleum Contractors Inc. for construction of production modules necessary to consolidate oil and gas from the wells. Both are subsidiaries of Arctic Slope Regional Corp. Production modules will be built in Anchorage and are scheduled to be installed on the North Slope early in 1995.

Obeney also cited cooperation and support of state agencies in facilitating production from Niakuk. "For developments like Niakuk that are highly cost and risk sensitive, it is critical that the state agencies understand the commercial risks and uncertainties and encourage development by being flexible," he said.

"In particular, the Alaska Department of Revenue's approval of commingling enables us to share production facilities among fields and reduce development costs. The Department of Natural Resources and the Alaska Oil and Gas Conservation Commission played key roles in supporting our development plans as well."

The Niakuk state leases were acquired by BP in 1967. Between 1975 and the mid-1980s, the company drilled nine wells. Data from a mid-1980s seismic program and results from Niakuk No. 6, drilled in 1986, prompted the company to proceed with plans to bring Niakuk on stream.

The nearby Alapah oil pool is part of Lisburne field but accessible from Niakuk. Owned by ARCO and Exxon 40% each and BP 20%, Alapah was found by a well drilled from Niakuk facilities.

MILNE POINT

Increased production is expected from the Milne Point field by yearend.

BP in early May started a 10 well program in Milne Point Unit as the first phase in an expansion project designed to boost production from the first quarter average of 16,700 b/d to 50,000 b/d by 1997. The first phase is expected to be completed by yearend.

Along with new wells, the company plans a $30 million upgrade of the Milne Point processing plant to increase capacity from the current level of less than 30,000 b/d to handle increased production. In addition to handling production from Cascade, the plant also will handle production from a find in the northwestern portion of the unit made in 1992 by Conoco Inc., former operator of Milne Point Unit. The Conoco discovery well, 1 Northwest Milne, in 25-14n-9e, flowed 300 b/d before operations were suspended in March 1992. Total drilled depth of the well was 11,060 ft. Vertical depth on bottom was 7,426 ft. BP expects to have Northwest Milne on line by yearend.

BP set the stage for its larger role at Milne Point late last year with acquisition of Conoco's interests on the North Slope in return for assignment of a 33% stake in BP's wholly owned Amberjack field in the Gulf of Mexico. Under terms of the deal, BP acquired Conoco's 64% interest in Milne Point field and related pipeline interests and 40% of the Badami discovery in the Beaufort Sea, as well as interests in 54 mainly deepwater blocks in the Gulf of Mexico.

BP also purchased Chevron's 27% interest in Milne Point field and related pipeline interests for an undisclosed price. BP now owns a 91% interest in Milne Point and is field operator, with Occidental Petroleum Corp. owning the remaining 9%.

Milne Point field, under Conoco's operation, began production in 1985. The field underwent a "warm" shut-in when operations became unprofitable after the 1986 oil price collapse and remained that way until April 1989. Cumulative production stands at 38.5 million bbl of oil.

At the time of the deal with Conoco, BP was earning a 35% stake in Badami by appraising the discovery.

The acquisitions gave BP access to two areas on the North Slope where economies of scale resulting from the company's other operations provide cost advantages to develop and produce more oil.

As for the future, BP's Davies said, "We see Alaska as a place having a great deal of resource potential, but right now it is at a competitive disadvantage because of low oil prices. The disadvantage comes from the fact it is a relatively high cost area.

"It's also remote from the markets and has a high marine transportation element, particularly for production that has to go to the Gulf Coast. That's restricted by the ban (on Alaskan North Slope oil exports). We're working to lift that constraint, which forces any oil that can't be placed on the West Coast to the Gulf Coast. That is clearly a disincentive for Alaskan development at times of low prices."