Alaskan North Slope operators are mounting a campaign to develop or expand production from marginal oil fields in the shadow of declining supergiant Prudhoe Bay oil field.
That's critical to slope producers not just in terms of maintaining oil production for its own sake.
As Prudhoe Bay's slide continues to pull down North Slope production, the economics of maintaining the Trans-Alaska Pipeline System (TAPS) comes under pressure as TAPS capacity utilization declines.
Most North Slope producers, notably the three biggest-ARCO Alaska Inc., BP Exploration (Alaska) Inc., and Exxon Corp.-also hold equity positions in Alyeska Pipeline Service Co., the Anchorage firm that operates TAPS.
Without enough other North Slope production to supplant declining Prudhoe Bay volumes and sustain the giant pipeline's capacity utilization, it wouldn't be long before the line is no longer economic.
Shutting down the pipeline would effectively shut in all North Slope production, which in recent years has accounted for 20-25% of U.S. crude oil output. So it follows that there is a sense of urgency in hiking the flow from producing marginal fields and finding ways to economically develop nonproducing marginal discoveries on the North Slope.
Fortunately, North Slope operators have a history of excelling at tweaking the economics of fields that would be plums in the Lower 48 but in this harsh, high cost environment are at the economic margin.
For example, Kurparuk River field on the North Slope went undeveloped for 12 years after its discovery in 1969 while ARCO and partners honed and sculpted field development plans into a commercial project. It is now the No. 2 producing field in the U.S. at about 300,000 b/d, and the process of reining costs and maximizing recovery continues.
Among the approaches North Slope operators are undertaking are contractor partnering, a notion pioneered in the North Sea (OGJ, Apr. 24, p. 32).
MILNE POINT'S REBOUND
While Prudhoe Bay field in the late 1980s kept Alaska in a tight race with Texas to see which would be the No. 1 U.S. oil producing state, Milne Point field adjacent to the northwest boundary of the Prudhoe Bay Unit struggled to survive.
In fact, Milne Point was shut in during January 1987-April 1989 because of low oil prices.
Although Alaska is in second place among U.S. producing states, Prudhoe Bay remains the top U.S. producing field. However, decline began in 1989, and operators are battling to hold the line with new technology and cost-saving alliances with service companies (OGJ, June 6, 1994, p. 23).
Milne Point won't come close to challenging Prudhoe Bay, but the field definitely is on the way up. The rise in Milne Point's fortunes underscores a major trend unfolding on the North Slope.
Milne Point, a 1969 discovery by Conoco Inc., is one of the smaller fields coming into focus as commercial contributors to Alaska's production. BP is emerging as a lead player in the campaign to bring more marginal fields on line, looking beyond Milne Point to the undeveloped Badami and Northstar/Seal Island fields.
Milne Point early this year produced 25,000 b/d, a record for the field. The increase is fueled by a $120 million, 3-year development program that includes expansion and enhancement of processing facilities and drilling 29 wells to tap the Northwest Milne Point reservoir. Additional drilling and investment planned for other parts of the field are expected to boost production to 50,000 b/d by early 1996.
"This program has also enabled us to double our projection of remaining reserves to more than 180 million bbl," said Howard Mayson, BP's Milne Point asset manager. Cumulative production to the first of this year was 43.6 million bbl.
BP acquired a 91.9% interest in the field and became operator a year ago. Production averaged less than 19,000 b/d in 1993 prior to BP's acquisition of Conoco and Chevron U.S.A. Production Co. interests Jan. 1, 1994. Occidental Petroleum Corp. owns the remaining 8.1% interest.
NORTHWEST MILNE POINT
Development of Milne Point reservoir is being extended to the northwest region of the field, and the capacity of processing facilities is being increased to 53,000 b/d. More than 50 million bbl of recoverable oil in the Northwest Milne area were confirmed by appraisal drilling in 1994. Other, smaller pools in the 71,000 acre Milne Point Unit are being developed as well.
Tom Gray, field manager, said Milne Point's expansion is tailored to minimize the development "footprint" on the tundra and to reduce environmental effects. Smaller production facilities, directional drilling, and elimination of drilling waste pits reduce the amount of surface area needed for development.
"Impacts on wetlands and wildlife habitat are key considerations in determining locations for new roads, pipelines, and gravel pads," Gray said.
Two rigs, Nabors Alaska Drilling's 22E and 27E, are drilling development wells in Milne Point, making the field one of the busiest on the North Slope. BP's 1995 capital spending plans include more than $100 million for Milne Point development.
The field faces a number of atypical commercial and technical challenges. It is the only North Slope field using electric submersible pumps to increase the flow of oil, yet the average Milne well produces less than 500 b/d of oil. The average well in Kuparuk River field produces more than 750 b/d, and the per well average at Prudhoe Bay is more than 1,000 b/d.
Milne Point field contains two productive oil formations: lower Cretaceous Kuparuk River at a depth of about 7,000 ft and upper Cretaceous Schrader Bluff at about 4,000 ft. Combined, they hold an estimated 2.5 billion bbl of original oil in place (OOIP). Kuparuk River pay is a high quality, consolidated sandstone that accounts for 25% of OOIP but more than 85% of current Milne production.
The shallow oil pay in the Schrader Bluff formation is highly unconsolidated, and its 2 billion bbl of OOIP is generally low in gravity at 14-20 and viscous, making it technically and commercially difficult to produce.
BP's 1995 drilling plans include six wells to recover oil from the Schrader Bluff reservoir, an extension of the West Sak formation in Kuparuk River field. The wells will test new ways to increase productivity and reduce costs of Schrader Bluff wells.
Schrader Bluff's unconsolidated sands tend to crumble when oil is produced, damaging production facilities. To solve the problem, BP has developed gravel packing technology that involves use of small diameter gravel outside the pipe as a filter to remove sand from fluid flowing into the pipe.
"With the right solutions to the technical and commercial challenges, we believe we can produce 200-400 million bbl of oil from Schrader Bluff," Mayson said.
"This would double the recoverable reserves again, and it would make Milne Point similar in size to larger North Slope fields like Point McIntyre and Endicott. It also could increase production to nearly 100,000 b/d by the turn of the century."
BOOST FROM CASCADE
Another boost to Milne Point production is expected to come from development of the Cascade discovery off the southeastern edge of the field.
BP tested the 1 Cascade strike, section 3-12n-11e, in first quarter 1993, confirming it with a sidetrack. The company took the well to 10,109 ft the first time down and to 9,175 ft in the sidetracked hole. BP said the well flowed at a sustained rate of 1,720 b/d from the Kuparuk River formation and other oil bearing zones had not been tested.
In permit applications filed last January, BP revealed development plans that include a 3.3 mile gravel road, a gravel drilling pad designated K Pad, and a 3.8 mile vertical member supported production pipeline from K Pad to Milne Point Unit E Pad.
The drilling pad will be developed in two phases. The first phase calls for 400 ft by 600 ft pad capable of accommodating 20 wells, the second an expansion to 400 ft by 900 ft to accommodate 20 more wells. Work was expected to begin in April with gravel placement.
A tentative timetable calls for a one rig drilling program to begin in September or October, with pipeline and flow line installation during December 1995-February 1996. Module installation is to take place in first quarter 1996, followed by well tie-in and start of production in second quarter 1996.
At peak flow, K Pad wells are expected to add 10,000-15,000 b/d of oil and 5-10 MMcfd of gas to Milne Point Unit production.
BADAMI PROSPECTS
Another new field on BP's agenda is Badami, a 1990 discovery by Conoco and Petrofina Delaware Inc. The discovery well, in 9 9n-20e, flowed 4,250 b/d. A confirmation well was drilled in 1992.
BP acquired Conoco's interest in the field with acquisition in January 1994 of the latter's North Slope interests.
Located 35 miles east of Prudhoe Bay, Badami is owned by BP 70% and Petrofina 30%. Badami's unit consists of 12 leases covering 48,492 acres. The field contains estimated potential reserves of as much as 150 million bbl of oil and 100 bcf of gas.
The approach BP is taking to develop Badami could shorten the period between discovery and production by at least 3 years and allow the company to begin production as early as 1997, said BP Exploration (Alaska) Inc. Pres. John C. Morgan.
If the company succeeds with its nontraditional approach, Badami could set an example for getting access to and developing smaller reserve pools on the North Slope.
One of BP's first moves at Badami was to run an extensive 3D seismic survey, completed last year. Last winter, the company started a two well drilling program, spudding Jan. 19 the 5 Badami in 5-9n-20e with Nabors' Rig 18E and Feb. 1 the 4 Badami in 3-9n-20e with Doyon Drilling's Rig 9.
"We hope to have the results assessed by fall," Morgan said. "Badami needs to hold at least 100 million bbl of recoverable oil to have a chance to make it commercially viable.
"Traditionally, we would be waiting for results of those wells before selecting contractors and proceeding with development plans and permitting," Morgan said. "But if we follow traditional paths to get from 'here' to 'there' with Badami, we risk not getting there at all.
"Timing is crucial if we are to successfully capture the development opportunities in Alaska's future. It's imperative that we shorten the period between discovery and production--the period when capital flows in only one direction, and that direction is out."
BADAMI DEVELOPMENT
BP began evaluating Badami development options many months ago, Morgan said, weighing options such as facility sharing vs. stand alone facilities, onshore vs. offshore pad, elevated vs. buried pipeline, and onsite staffing vs. remote operations.
Pending results of appraisal drilling, the company is looking at developing Badami from a single onshore well pad with stand alone processing facilities. A small crew of about 12 would operate the field, with no road access to other North Slope installations. Access to the field in the winter would be by ice road and in the summer by barge and helicopter.
Extensive use of extended reach drilling would tap Badami pay, which mainly underlies Mikkelsen Bay. Plans call for drilling 60 wells: 40 producers, two gas injectors, and 18 produced water injectors.
Capital expenditures for Badami initially were estimated at $780 million. The goal now is to cut costs to $320 million for the entire project.
A key element in cost saving is the pipeline for Badami production. Present planning calls for moving Badami crude through a 28 mile buried pipeline to the Endicott oil sales pipeline. To protect permafrost, crude would be chilled to 30 F. at Badami and reheated to 120 before entering the main Endicott line for shipment to TAPS Pump Station 1.
The 20 in. carbon steel line would be capable of handling Badami production at rates of as much as 50,000 b/d. It's estimated the underground line would cost $50 million, compared with $180 million for an elevated pipeline and bridges crossing four rivers.
Further reduction in project costs would come from building more compact production facilities, perhaps using existing designs and equipment to reduce the amount of engineering work.
If BP's board approves the Badami project this fall, construction of drilling pad, facilities pad, dock, airstrip and an in field road system would occur in winter 1996. Pipeline construction and initial development drilling would occur in winter 1996-97, with development drilling continuing through 1999.
Modules would be delivered by sea and installed in summer 1997, paving the way for production start-up in fourth quarter 1997.
In the meantime, BP hired five contractors to provide design and construction services for surface production facilities associated with possible Badami development. The five will work as a team throughout the preliminary engineering phase of the project to reduce costs and help make development commercially attractive.
The contractors are Houston Contracting Co.-Alaska Ltd., a subsidiary of Arctic Slope Regional Corp., Anchorage, pipeline installation; Veco Construction Inc., Anchorage, module installation; Alaska Interstate Construction Co., civil works, primarily gravel work; National Tank Co., Houston, vessel and skid fabrication; and Colt Engineering Corp., Calgary, facility and pipeline design.
Along with evaluation of the two appraisal wells drilled last winter, a decision on whether to develop Badami will hinge on permitting, unitization, and other regulatory considerations, as well as the success of cost cutting efforts.
"In order to make development commercially attractive, we must reduce costs by more than half from our initial projections," said Terry Obeney, BP's manager of new developments.
"The purpose of naming contractors now is to get them working together as a team to align their interests and identify innovative ways to reduce costs without compromising safety or technical standards," Obeney said.
"While this is a new way of doing business in Alaska, it's been used effectively to develop marginal fields in the North Sea. It's one example of how we hope to work together with contractors to compete for investment capital for marginal projects here."
NORTHSTAR/SEAL ISLAND
BP also is training its sights on Northstar/Seal Island field, a 1982 discovery by Shell Western E&P Inc. in the Beaufort Sea 8 miles north of Milne Point and Prudhoe Bay fields.
BP set the stage in January by acquiring Amerada Hess Corp.'s 81% interest in the Northstar Unit and followed up with acquisition of Shell's 17% interest, bringing BP's ownership to 98%. The remaining 2% is owned by Murphy Oil USA Inc.
The 30,788 acre Northstar/Seal Island unit is believed to hold 100-200 million bbl of recoverable oil. The unit consists of state and federal leases.
"Northstar is a marginal development opportunity that still faces very significant commercial and fiscal challenges," said Eric Luttrell, BP Exploration vice-president of exploration and development.
"We're hopeful that by working cooperatively with local, state, and federal agencies, we'll be able to secure a favorable investment climate that enables us to develop it. We're confident in our ability to work with contractors to overcome the commercial challenges."
BP plans to submit a development plan for Northstar/Seal Island before the end of the first half to the U.S. Minerals Management Service and the Alaska Department of Natural Resources (DNR). BP does not plan more exploratory wells for Northstar/Seal Island but hopes to have the field on production by the turn of the century.
Shell Western E&P Inc. drilled the Northstar/Seal Island discovery from manmade Seal Island in 39 ft of water 6 miles off the Kuparuk River delta. On tests of three Triassic-Permian Sadlerochit intervals, the 14,541 ft well flowed 40 gravity oil at stabilized rates of as much as 5,000 b/d through 1/2-1 in. chokes.
Two appraisal wells confirmed the discovery. A third appraisal, drilled across a fault, was plugged.
Amerada Hess in early 1986 disclosed discovery of an extension to the field with 1 Northstar Island, drilled from manmade Northstar Island 5 miles west of Seal Island. The 11,800 ft well flowed oil from Sadlerochit at rates of as much as 4,700 b/d. Oil gravity in the 40's was similar to that in the Seal Island wells.
In addition to acquiring Amerada's interest in the Northstar Unit, BP purchased 75% of the company's interest in 15 tracts covering 37,675 acres offsetting BP acreage off the western edge of the Arctic National Wildlife Refuge (ANWR). Amerada retained a 25% interest.
The acquisition heightened speculation over what BP encountered in a pair of wildcats drilled in 1994 in the Staines River area outside the ANWR border 50 miles east of Prudhoe Bay field. The wells were 1 Yukon Gold, 13-8n-23e, abandoned at 12,800 ft; and 2 Sourdough, 31-9n-24e, 3 1/2 miles northeast of the Yukon Gold well.
The Sourdough well went to an undisclosed depth before the rig was released 2 1/2 months after spudding. Details were not disclosed for either of the wildcats, but the state certified Sourdough as "capable of producing in paying quantities."
UNION TEXAS, KUVLUM
Union Texas Petroleum is another operator taking a new look at a North Slope marginal field, Kuvlum.
Offshore Kuvlum field had fueled hopes for 1 billion bbl development in 1992 with a discovery well that flowed at a rate of 3,400 b/d of 34 gravity oil only to see hopes dashed in 1993 with the drilling of two follow-up wells that failed to support earlier enthusiasm.
In the wake of the disappointing 1993 season, ARCO, while noting Kuvlum contained "a substantial accumulation of hydrocarbons," described the field's resource as "not commercial as a stand alone development" and scrapped the prospect.
Union Texas, which held a 20% interest in the Kuvlum prospect, last February increased its holding to 100% by acquiring ARCO's 50% interest and minor interests held by Murphy, Phillips Petroleum Co., Total Minatome Corp., and Mobil Exploration & Production U.S. Inc.
MMS approved the acquisition and made Union Texas the new operator for the 35,000 acre prospect, which lies 16 miles off the western edge of ANWR and 60 miles east of Prudhoe Bay field.
OTHER MARGINAL FIELDS
Another Beaufort Sea marginal field that might get a delayed chance at making a contribution is Hammerhead, a 25,000 acre unit that includes four federal leases 20 miles north of ANWR.
Shell last February acquired Amoco Production Co.'s two-thirds interest in the unit, giving the company 100% ownership. MMS designated Shell unit operator and required the company to submit a development plan by the end of May.
Previous drilling on the prospect included the discovery well in 1985 and one confirmation well. Reserve estimates have not been disclosed.
Sandpiper field also is a marginal field that could draw attention if BP elects to proceed with Northstar/Seal Beach development.
Soon after Amerada Hess in 1986 disclosed extension of that field with the first Northstar well, Shell enhanced the possibility of commercial development in the area with acknowledgement of a discovery on manmade Sandpiper Island 11 miles northwest of Seal Island.
Shell's discovery well flowed at stabilized rates of 500-2,500 b/d of 40-52 gravity oil through 30/64-2 in. chokes. Flows in the 12,575 ft well came from two Sadlerochit zones below 11,910 ft measured depth. The well also produced gas at a rate of 18.5 MMcfd.
GAS FIELDS
The future of three discoveries of the 1970s west of the ANWR boundary is uncertain.
One of the fields is Point Thomson, a 1977 gas/condensate find drilled by Exxon 5 miles west of ANWR and 50 miles east of Prudhoe Bay. The discovery well, 1A Alaska State on Flaxman Island, and confirmation wells proved reserves estimated at 3 tcf of gas and 200 million bbl of condensate.
Kavik and Kemik gas fields farther south are believed to hold more than 1 tcf of gas reserves. With no present means of marketing North Slope gas, the two gas fields are unlikely candidates for early development.
Alaska's DNR, impatient over the delay in Point Thomson development, gave Exxon notice to come up with an acceptable development plan by Apr. 30 or face losing about 55,000 acres from the 83,825 acre Point Thomson Unit. Acreage sliced from the unit would be offered as part of a North Slope lease sale in 1998.
WEST SAK
A huge, currently noncommercial oil pool that has been on the back burner since 1989 on the North Slope is once again under study for possible development.
The resource is the West Sak pool, which overlies deeper producing horizons in Kuparuk River field. West Sak contains about 16 billion bbl of OOIP, or about 6 billion bbl less than Prudhoe Bay's OOIP. West Sak crude gravities range from less than 15 to 22, but closeness to permafrost gives it a high viscosity likened to molasses.
"We have formed a West Sak assessment team and will work with co-owners and with the ARCO Exploration & Technology Group at Plano doing some new research," said Ken Thompson, ARCO Alaska president. "We will be looking at technology support and research."
Thompson said the assessment team is looking at directionally drilling multiple laterals as a possible means of reducing drilling costs by as much as 30%. Completion technologies also are under study.
The West Sak sand is a very friable unconsolidated rock, which poses the problem of keeping sand entry under control while still allowing good production rates.
"We are examining different miscible gas injection scenarios and comparing that with waterflood to see if we can find a viable commercial process,Thompson said. "We are also looking at different ways of lowering costs of facilities."
The timetable calls for completion of studies by late summer.
"At the end of studies, we will assess moving ahead with field work," Thompson said. "If we find the project is still not commercial, we will work with the state of Alaska to consider tax or royalty changes to move West Sak and see if we need any federal assistance for heavy oil."
West Sak has been in limbo since 1989, when ARCO suspended a 25 well drilling and production test program designed to bring the pool on production in the mid-1990s. The company blamed suspension of the program on changes by the state in the economic limit factor (ELF), which helps determine oil and gas severance tax assessments, that were aimed at increasing severance taxes in Prudhoe Bay and Kuparuk River fields.
West Sak would be affected because plans called for producing Kuparuk's developed pay and the shallower West Sak pay through the same facilities.
Changes in ELF meant West Sak production would be penalized by higher taxes if it were combined with Kuparuk production. ARCO said the project could not afford higher taxes, nor could it afford the cost of installing a duplicate set of facilities.
The revival of interest in West Sak, Thompson said, stemmed partly from decreased drilling costs and in part because state leaders were open to providing economic incentives that would help companies develop marginal fields.
Copyright 1995 Oil & Gas Journal. All Rights Reserved.
