During the past 5 years the well construction sector has witnessed many radical changes, including the emergence of new breakthroughs that reduce cost and risk and the evolution of state-of-the-art technologies that increase oil recovery.

New technologies finding their way into well completions promise a fundamental change in well management techniques.
Wells containing these permanently installed devices have been termed "intelligent." Brock Williams, BP's Intelligent Well project manager, said the basic purpose of these devices is to acquire surveillance information about the health of the well and control flow from various zones without intervention.
Surveillance devices measure well pressure, flow rates, fluid composition and temperature distribution. Flow control devices typically are sliding sleeves with actuators that can be installed to open, close or choke flow from multiple zones within a well.
Permanently installed electronic pressure gauges have been available for some years, and thousands have been installed. These have demonstrated the value of a continuous single-point measurement of pressure.
Williams said the future holds the promise of improving this performance through fiber-optic technology. Small quantities of first-generation fiber-optic gauges have been installed on the Gyda and Marnock fields in the North Sea. These systems suffered from low accuracy and degradation of the optical fiber clarity over time. But a new generation of fiber-optic gauges and cables on the market offers better accuracy and improved optical clarity. A field trial of the new-generation optical pressure gauge took place in the US Gulf's Pompano field earlier this year. Three additional installations are planned by the end of this year.
However, for intelligent well devices to gain broad acceptance, a higher level of confidence in their reliability will be required, Williams said. "Our industry has historically not been very good at accurately assessing reliability of complex mechanical systems for downhole use. The aerospace and space industries have developed techniques and processes for performing these types of analysis. The Intelligent Wells project is currently engaged in an initiative with a leading aerospace firm to understand those processes and work with our industry's technology providers to incorporate these processes into future product design."
Paul Martin, BP's head of well performance, reiterated the growing importance of intelligent completion (IC) technology. "We have focused primarily on surveillance technologies because so many reservoir development and management decisions are dependent on the data.
"A particular highlight has been the rapid advance of fiber-optic surveillance technologies, which offer both novel sensing capabilities (for example, the Wytch Farm field's use of fiber-optic distributed temperature systems), and the possibility of a step change in long-term reliability," Martin added.
The future for IC can best be described as uncertain. The economic rationale is clear, yet field application will very much depend on oil price.
Mark Docherty, business manager for permanent monitoring at the Expro Group, based in Aberdeen, Scotland, said IC will need a profitable industry to kick start the S curve. Once this technology gets into the field, it must deliver the benefits sold, he said. If this can be achieved, even a drop in oil prices should not adversely affect the takeup of the technology, as the cost benefit will have been proven.
Expro brings significant permanent monitoring experience to the IC industry. Its expertise lies in cutting-edge communication systems, including a decade of experience in downhole electronic sensors, telemetry systems, data interrogation and management systems. Expro recently introduced the Harvest system, which produces a fully addressable, digital multichannel architecture. This system will allow up to 256 nodes to record, interrogate and control downhole processes on a single cable. Harvest comprises three core module types that, by design, permit open arrangement of sensors to suit all well geometries and completion designs.
So what other step changes might take place? How will operators continue to slash unit-operating costs?
BP recently unveiled a range of strategic technology imperatives geared toward optimal performance. It claims optimal performance has the potential to significantly increase cash flow from a combination of improved capital efficiency, early project delivery and growth.
Realization of the potential will come in part through the application of various innovative technologies.
No drilling surprises. Essentially, this project is geared at established tools and techniques to incorporate into well planning and operations activity that significantly reduces the subsurface uncertainty and eliminates costly borehole problems.
Rig modifications. Several emerging technologies could improve operating performance for deepwater developments and extend the operating envelope of early generation semisubmersibles. Many of these are ready for field application. The immediate focus relates to identifying specific field trial opportunities, particularly for the polyester mooring and freestanding riser projects.
Underbalanced drilling. The application of underbalanced drilling technology could unlock significant value in BP's mature gas assets. The UK giant has had limited, but successful applications of this technique for onshore operations in the US Lower 48, Canada and Sharjah, and Algeria and Colombia are planning to adopt the technology.
Expandable tubulars. The monobore concept for well design, where there is little material reduction in wellbore diameter from the mud-line to total depth, delivers maximum productivity with minimum diameter subsea equipment. This cannot be achieved with conventional technology, but expandable technology offers this vision. Successful delivery obviates the need to develop large-bore 15,000-psi wellheads and blowout preventer stacks, and has a significant impact on well costs.
Dual-gradient drilling. The deepwater basins are characterized by narrow pore and fracture pressure windows. This means that under conventional well design criteria, five or even six casing strings are required prior to penetrating the reservoir. This increases the capital cost of the wells, adds significantly to the time taken to drill them and necessitates large wellhead diameters. Hence, reducing the number of casing strings through innovative approaches becomes paramount. BP believes dual-gradient drilling techniques, where the excess hydrostatic pressure from the drilling riser is negated, offers this potential.
Ultrareach wells. Within the Alaskan business units are large reserves that are either uneconomic or environmentally risky to develop. In other areas are deeper reserves, which also cannot be accessed by existing technologies due to the combination of depth and lateral departure. To tap these, the industry needs to develop technologies to allow the equivalent of 30,000ft to 40,000ft (9,150m to 12,200m) departures from the drilling center and high-angle wellbores at depth. BP suggests step-change technologies will be required to achieve these objectives.
And how will completion installation performance costs be increased?
In addition to the six drilling technologies, BP has identified two completion technologies that could be key in the battle to achieve optimal drilling performance: expandable sand screens and intelligent wells.
Most future deepwater production is dependent on effective sand control completions, with the key challenges being achieving maximum well deliverability while ensuring long-term well integrity and manageability. Sand control technology is evolving rapidly, and expandable sand screen technology, in particular, offers the potential to reduce completion costs and increase long-term well manageability, especially if combined with solid expandables to achieve zonal isolation capabilities. BP's upstream technology group well construction leader, Paul Adair, said in the company's internal publication, WellConnected, that on the UK Continental Shelf (UKCS), average costs per well were almost halved between 1996 and 2000. The reductions resulted in a US $192 million (£128 million) saving compared with previous performance.
Finder wells
Another challenge for operators will be how to reduce well costs further. On the UKCS, finder wells are a familiar and favored concept. At a recent Society of Petroleum Engineers meeting in Aberdeen, Scotland, Steve Cromar and Sayma Akram from Conoco's well operations team spoke about the concept and its application.
"The idea originates from a plea to the well operations group from John Williams, the Conoco exploration manager. In 1998 with $10 oil, $29 million wells west of Shetland were not an option. If well costs did not reduce, exploration drilling was at risk."
The main goal of a finder well is therefore to reduce costs. Cromar suggested starting with a basic well design and justifying absolutely everything additional as the way to achieve lower costs. "The pure finder well strategy would be to drill a vertical well as fast as possible down through the prospective zones to establish whether hydrocarbon-bearing sand is present. The casing design is an absolute minimum - if you know you will only run one log and not put in casing, you can take more risk in terms of reaching the target. Even if we lose a well or need to drill a subsequent appraisal, the finder well concept represents far better value in the long run."
Akram continued with a description of the first finder well drilled west of Shetland. "The harsh environment and deep water presented a great enough challenge without trying to halve drilling costs," she said.
"Our main objective was to prove the finder well concept in the field. We had drilled two previous exploration wells in the area, both with a 36in. conductor and two or three additional casing strings to get us to (total depth) and gather the data required. There was one casing string for each drilling hazard identified. The finder well had a 36in. conductor and only one additional casing string. There were absolutely no additions. We were to drill down as fast as possible, establish the presence of hydrocarbon-bearing sands and if there were none, to get out."
This finder well was drilled successfully at the planned cost of $15 million (£10 million).
Anaconda
Halliburton recently unveiled another radical new well construction system - Anaconda, developed jointly with Statoil.
According to Halliburton, the key enabling technology is a carbon fiber coiled pipe - known as SmartPipe - that is lighter than steel and has substantially improved fatigue characteristics. It also features wires built into the structure. The entire bottomhole assembly has been engineered to take advantage of this pipe and includes a 3D real-time steering tool, a drilling tractor, advanced formation evaluation tools and comprehensive real-time measurement of drilling parameters.
Anaconda is in the latter stages of testing. It has drilled more than 4,500ft (1,373m) of open hole and is scheduled to drill its first commercial wells early this year.
Acknowledgements
Information for this article came from BP's in-house publication WellConnected and authors Brock Williams and Paul Martin, and the November issue of the SPE Review. Mark Docherty at Expro group, Steve Cromar at Conoco and Kevin McMillin at Sperry-Sun also supplied additional information.