AMSTERDAM CONFERENCE- Conclusion: Mature well technologies must become cost-effective, standardized

April 11, 2005
Mature oil and gas fields require efficient technologies tailored for low-cost operations, according to a panel of industry experts.

Mature oil and gas fields require efficient technologies tailored for low-cost operations, according to a panel of industry experts.

This article presents the highlights of the last of three plenary sessions at the drilling conference in late February, sponsored by the Society of Petroleum Engineers and the International Association of Drilling Contractors (IADC).

The third plenary session, "Mature Well Technologies—A Growing Challenge," was moderated by Bill Pike, editor-in-chief at Hart's E&P magazine. The panel included Gary Warren, president of drilling and well services, Weatherford International Ltd.; John Crum, executive vice-president at Apache Corp.; Omar Al-Husaini, manager of the gas drilling operation department, Saudi Aramco; Jon Goodale, vice-president- North Sea for Challenger Minerals Inc. (CMI), an upstream subsidiary of GlobalSantaFe Corp.; and John Gerstenlauer, managing director at Wintershall Noordzee BV, part of the BASF Group.

Mature wells

John L. Thorogood, exploration manager at BP PLC and past SPE technical director, drilling and completions, introduced the session.

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Using wireless voting pads, members of the audience, representing operating, drilling, and service companies, participated in nine questions (Table 1). 40% believed that technology was the most pressing issue for the future development of mature fields.

A BP project manager from Aberdeen was one of the 33% who believes that economics is the primary driver of decisions. But he said "we need more creative solutions."

Weatherford's Gary L. Warren said that the oilfield has two significant aging issues: its workforce and its producing wells. 90% of producing fields are greater than 20 years old and brownfields have only a 35% recovery factor. In order to maximize the value of a mature field, Warren said the aim is to drill low-cost, high productivity wells, and design low-cost abandonment procedures.

He mentioned classic techniques used to renew mature wells: drilling sidetracks, multilaterals, and stimulating wellbores. Newer techniques include extended reach drilling, drilling with casing, managed pressure drilling (MPD), and underbalanced drilling (UBD) using coiled tubing (CT). These technologies allow drillers to reach TD using unconventional means, to avoid depleted zones and nonproductive time.

In the Gulf of Mexico, for instance, fields that were never properly developed, or previously inaccessible due to pressure transitions or shallow water flows, can now be exploited using drilling hazard mitigation tools and systems.

In order to maintain high productivity, Warren said production technologies must cause less drawdown on the reservoir pressure and provide better reservoir "sweep." They must include water or gas shut-off techniques and also provide low-damage completions. The key enabling technologies are expandable tubulars, UBD, downhole isolation valves, and stimulation enhancements.

Abandonment, brownfields

The goal for abandonment is to limit the amount of money you spend at the end of a well's life, Warren said. Plans for low-cost abandonment and decommissioning are driven by regulatory requirements and compliance with safety protocols. Key technologies are interventional (fishing, cutting, milling, plugging), rigless intervention, and tubular handling, with focused project management.

Typically, drilling engineers don't worry about structure removal or intervention, Warren said. "Drillers, at the front end, need to be mindful of decommissioning at the back end" from an engineering standpoint.

Warren thinks brownfields will remain our greatest potential source of hydrocarbons. He cited Hugoton, the largest gas field discovered in North America (Kansas, Oklahoma, Texas), in which severe depletion has created dramatic lost circulation problems, resulting in formation damage and permanent productivity reduction. UBD techniques are improving incremental production rates by 300-400% above conventionally drilled and completed wells, he said.

Service companies and operators already have many of the tools needed to take advantage of mature reservoir plays, according to Warren. How can we use what we already have?

Favorite truths

John Crum said that Houston-based Apache increased its holdings from 133 fields in 1995 to 263 fields in 2003, but that the average boe/well has decreased significantly.

He used the Forties field in the UK North Sea as an example of a mature field, with 185 wells and an average 14 mboe/well. On Apr, 2, 2003, Apache completed its $630 million acquisition of the field, with 148 mboe estimated proved and 57 mboe probable reserves.

The last active drilling was in the early 1990s, Crum said. The drilling challenge has been to drill targets smaller than a million bbl profitably. The company was faced with obsolete drilling equipment and a poor support infrastructure. Crum noted that in mature fields, operators might run out of spare slots, or have company culture of risk avoidance.

Crum listed his "favorite truths" for working in a mature field:

  • Only "new" oil pays for additional investment.
  • "Mature" fields produce less oil and require more wells.
  • Can't control product prices, but can control costs.
  • Use technology and common sense; get back to basics.

At the Forties field, Apache used several cost saving measures, removing a workover rig at Echo and reactivating four platform rigs. The company abandoned wells offline, plugging them ahead of the rig, and saved ¤0.3 million/well. Apache used rotary steerable tools and LWD to cut drilling times, and casing drilling to run ultra long 7-in. liners in 60-70º holes. Crum noted that in 2003-04 at Forties, Apache ran eight of the 10 longest liners in the world. He also said that using horizontal trees simplified completions and future workovers.

Early cost estimates were ¤8-12 million/completed well. The 2004 program at Echo was planned for ¤4-5 million/well, although the actual cost was about ¤6 million/well with two total write-offs. In 2005, the plan is to spend ¤4 million/well, and the company had already completed four wells for under ¤3 million each.

After the aggressive drilling program in 2004, Crum said Apache has added about 175 mboe, for a total potential of 400 mboe in the Forties field.

Separation technology

Omar Al-Husaini, Saudi Aramco, noted that the Saudi Arabian Oil Co.'s fields "are not as mature as some out there," but said that the industry needs to take a proactive approach, ahead of field maturity, to manage reserve depletion and high water production in older fields. He sees producing bypassed oil as a primary focus in operating mature fields.

Al-Husaini thinks that advances in geosteering technology will be a useful, allowing more accurate placement of wellbores. Drilling multilaterals will allow for maximum reservoir contact (MRC) and enhanced production.

A second important focus is on technology that controls, minimizes, or eliminates high water production, he said. More sophisticated systems now include a focus on MRC using smart well completions, production equalizer systems, and expandable tubulars, although the latter technology isn't currently useful in high-temperature, high-pressure wells.

A downhole separator that can separate oil and water and inject water below the production zone would be very useful, Al-Husaini said, along with inline separators that separate at surface, near the wellhead. He also thinks 4D seismic and advanced reservoir characterization techniques would be of great help in mature field management.


Challenger Minerals is involved in collaborative G&G projects and has an equity interest in 135 wells in the Gulf of Mexico and North Sea, according to Jon Goodale. He presented a solution for a supermature brown field (SMBF), citing a brownfield project in the Gulf of Mexico that involved Applied Drilling Technology Inc. (ADTI), a subsidiary of GlobalSantaFe that provides turnkey well solutions. The 45-year old field lies in 40 ft water. The partners drilled 22 wells in 1999-2000 for $23 million, reducing estimated costs by 30%.

How to rejuvenate a SMBF:

  • Exceed safety standards.
  • Assemble appropriate human resources.
  • Inject project capital and improve return.
  • Use fit-for-purpose, standard equipment.
  • Manage the capital risk of drilling operations.
  • Use offshore turnkey solutions.

Goodale noted that these opportunities are going away, with $50/bbl oil.

Related challenges

Wintershall Noordzee is interested in gas, and doesn't have any mature fields, said John Gerstenlauer. However, the company looks for small fields, about 2 billion cu m, produced from small platforms, which present high risk for low rewards. Despite Wintershall's extensive 3D coverage and use of a 3D visualization room, there are still drilling and reservoir risks, and the high cost of working in the North Sea. The company's acreage spans four countries with disparate regulatory regimes. The shallow water is busy with shipping, fishing, recreational, and military activities.

The main challenges to development, though, are the increasing rig rates and price of steel, necessary for casing, platforms, and pipelines. The reservoirs are small, with poor seismic definition below the salt, and require deep, high trajectory wells.

Gerstenlauer discussed the A6-B4 field, the Entenschnabel project, Germany's only offshore natural gas field, controlled by the Deutsches Nordseekonsortium (German North Sea consortium), comprising Wintershall (operator; 49.95%), BEB Erdgas und Erdöl GMBH (40.45%), RWE Dea AG (7.1%), and EWE Aktiengesellschaft (2.5%). The field was discovered in 1974, although production only began in September 2000, at 116 MMcfd (OGJ, Apr. 16, 2001, p. 36). The three production wells were drilled in 48 m water depth from the Transocean Nordic jack up, with 600-800 m step-outs.

In comparison, wells are now being drilled to about 1,700 m deep, with 5,000 m step-outs. The L6-6 well, deepest well in the southern North Sea, was drilled on the Dutch continental shelf in 2004, directly through a salt dome, said Gerstenlauer.

What's needed

He says the industry needs better, more affordable rotary steerable systems and wireline logging. The cost of directional drilling must be reduced. Average well costs are now ¤10-15,000/day, and rigs are running ¤60-70,000/day.

The industry would benefit from geosteering technology that incorporates geochemical analyses, Gerstenlauer said.

He noted that Carboniferous period cherts are particularly abrasive, requiring improvements in PDC cutter quality and durability. Environmental rules require high performance, water-based muds. Better muds and higher torque mud motors are needed.

Gerstenlauer said that heightened environmental sensitivity means that it becomes more difficult to get chemical use permits for drilling.

Goodale agreed that regulatory requirements are most onerous when they delay operations. If you miss a drilling window, and must pick up a rig later at higher cost, the economics of the project can be significantly altered.


The audience was polled on which type of company is best equipped to provide solutions for mature fields; 47% believed it will be integrated service cos. (Table 1). The next highest response was 19% for independent operators. Only 1% believed that national oil companies were well equipped to deal with this. Roy Marker, manager for well technology and drilling technology at Statoil ASA, Stavanger, and member of the conference program committee, said he was surprised by the results, insisting that NOC's have good strategies.

John Crum, Apache, agreed saying "National oil companies control the lion's share of oil in the world; they will have a huge role to play." But Crum also noted that it is no surprise that service companies are expected to be the lead technology providers.

Moderator Bill Pike asked panel about the expected personnel shortages. Wintershall's Gerstenlauer noted that in the mid-1980s there were about 30,000 petroleum engineers in the US, but now there are only 18,000, leading him to wonder what the industry would look like in 20-30 years. Weatherford's Warren said younger engineers need to attend conferences, and Crum added that younger engineers are not being given enough opportunities or responsibilities.

Why are new engineers held back? The panel speculated that it is the high cost of failure offshore, although there are opportunities for repeatable, multiple well operations in drilling campaigns throughout the world.

Colin Leach, president of Argonauta Drilling Services LLC, speculated that real-time data transfer means that more people may be watching young engineers work, and too much oversight may be daunting. And panelists noted that the industry needs better, more positive PR in order to attract and keep talented people in the field.


Costs are expected to decrease when industry standards are adopted. Akin to the price drops in consumer electronics, certain drilling operations will benefit if they are standardized and compatible. Detailed specifications could be revised to eliminate preferential engineering requirements for non-standard items. Regulatory structures also need to be streamlined.

For instance, a rig equipped to drill HPHT wells in the Gulf of Mexico cannot just sail into the North Sea and begin work, because of a multitude of regulations. Gerstenlauer noted that even moving a rig from the Dutch sector to the UK sector of the southern North Sea would cost $400,000 in upgrades.

The service industry also wants standardized contract terms and conditions, Warren said. Contract terms vary not only between companies and geographic areas, but also within the same operating company, he said. Operators too often use contract terms as a negotiating tool, requiring additional work by legal staffs.

In 1993, the CRINE program (Cost Reduction in the New Era) was initiated for the North Sea, and industry members designed a set of manufacturing and contractual specifications in an attempt to cut costs by 33%. Although Aberdeen-based UKOOA notes an "increasing use of alliance style contracts, with risks and rewards being shared by the parties," Warren told OGJ that in reality, most operators sought to modify the standards, and CRINE contracts are now only used by some independents in the North Sea.

CRINE was supplanted in 1999 by the LOGIC (Leading Oil & Gas Industry Competitiveness) Ltd. initiative, stressing supply-chain management as a more effective cost reduction tool. However, the disparate benefits and negative impact of supply-chain management systems were noted in the earlier plenary sessions (OGJ, Apr. 4, 2005, p. 45). Other standards organizations (ISO, API) provide some international standards for industrial applications, but more work on standardized contracts is needed, Warren said.