Active control is a key factor in intelligent well completions
Maximize final recovery of reserves through an exploitation strategy based on maximum control, real-time monitoring and closed-loop capability.
Jesus Contreras and Fernando Kirnbauer, Baker Hughes Incorporated
Intelligent Well System (IWS) completions provide absolute control over reservoir exploitation. The four most important reasons to install an IWS completion are to maximize final recovery of reserves, accelerate/optimize production, reduce intervention operations and minimize environmental impact.
The key factor in maximizing final recovery with an IWS completion is to provide the capability of modifying the production or injection conditions of the well according to the depletion process of the reservoirs or as the result of changing operational conditions. This is active control. The purpose of this control concept is to provide maximum capability to adapt to the variable conditions of the reservoir. There are two control levels: on-off and adjustable (choking capability).
Deepwater: A robust market in an uncertain climate
Despite the global economic crises, another run-up in oil prices due to fears of a global oil shortage will increase the economic viability of deepwater E&P.
Steve Robertson and Thom Payne, Douglas-Westwood Ltd.
A future peak in world oil supply is inevitable; the only question remaining is the date that this will happen. In recent years the world has witnessed oil price shocks driven by oil supplies having become very tight, as spare capacity was absorbed by growing demand for energy worldwide. Future projections of oil supply and demand suggest that this situation is likely to repeat.
The implication of this supply scenario is that we expect to see a sustained increase in oil prices as supplies tighten in the run-up to the peak year. This will affect deepwater developments to the extent that they will become more economically viable as the oil price rises. Developments that were marginal at $20/bbl will undoubtedly be more vigorously pursued in an environment where the long-term expectations of oil price are $60/bbl and upward.
Field redevelopment accomplished using advanced RSS
Rotary steerable and geosteering technologies enable rapid field redevelopment.
Jim Manson, Andy Stewart, Martin Pendlebury and Emily Ferguson, Maersk Oil, UK; Ukpe John, Ian Tribe and Rebecca Lepp, Schlumberger
Dumbarton Field, operated by Maersk Oil, UK, is located in UK North Sea Block 15/20. During its life, the field presented numerous drilling challenges, which hampered its development. These include formation instability, directional drilling control issues and thin, complex reservoirs that were poorly imaged by seismic. Drilling is further complicated by transition drilling—alternating zones of fast drilling separated by slow-drilling, hard, abrasive stringers. The field pore pressure gradient is 9.07 ppg equivalent mud weight; but to maintain wellbore stability, mud weights up to 11.6 ppg are required. Because of these and other challenges, traditional mud-motor directional drilling has been sub-optimal.
Discovered in 1987 by BP, the field was originally Donan Field. The discovery well, 15/20a-4, and a single development well, 15/20a-6, provided production during the subsequent 10 yr and accounted for a cumulative 15.3 million bbl of oil. In the latter half of the 1990s, additional horizontal development wells were planned to replace the two producers. Five attempts were made, but all failed due to wellbore stability issues. BP continued production from the original two wells until 1997. Watercut had reached 71%, and production ceased to be profitable.
Maersk Oil UK acquired the field and assessed the seven wells in the vicinity that intersected oil in Paleocene sandstones. These included the wells of Dumbarton/Donan Field and the smaller Pladda Field to the east. The reservoirs are low-relief, areally-extensive structures with thin oil legs from 30-ft to 100-ft thick, which are aquifer driven. Well tests were performed in one Jurassic and three Paleocene sequences; each flowed oil at 3,000 bpd. Production was good quality, undersaturated oil with a gas/oil ratio of about 400 ft3/bbl and an API gravity of about 40°. The reservoir sits atop a thick Balmoral sand package with average porosity and permeability of 30% and 1 Darcy, respectively. The sand is layered with thin, laterally-extensive shales.
The deciding factor for the redevelopment was the revelation that the original oil in place was estimated at 150 million bbl. Almost 90% of the oil was still in place. In addition, the economic climate had changed dramatically since the late 1990s. Accordingly, five production wells were planned to exploit the field along with a single water injection well.
Laser scanning provides extra value in project design
Scanning an existing processing facility into a 3D virtual environment helps determine remedial pipe runs and create up-to-date drawings.
David S. Stevens and Christopher T. Comardo, Mustang Engineering, Houston
Laser scanning technology has existed for less than a decade, yet it has already become a powerful tool in the oil and gas industry, gaining wide acceptance for brownfield applications, both onshore and offshore. Its use is especially important in an economic climate where budgets are curtailed and renovating existing facilities is a crowded operation. Offshore platforms are a good example, as they can be as complex as a refinery but with much less real estate to work with.
Laser scanning is a means of obtaining a 360° data capture, providing a 3D view of a facility. With a scanning camera operating at ultra-fast speed, it collects up to 500,000 individual surface geometry measurements per second and creates a “point cloud” that can be viewed with specialized software. Basically, laser scanning brings a “smart” digital picture of a facility back to a designer who, using the industry’s predominant 3D CAD modeling software, can design or redesign facilities. It can add surety to cost, implementation and safety to redesign.
While this technology is mostly used for brownfield work, laser scanning also has applications for new construction. Dimensional control of piping spools being welded in fabrication yards is one application. Another is the verification of correct placement of vessel flanges and the orientation of other equipment on skid modules in the yard. This accuracy is especially important with high-alloy, high-wall-thickness steel, where rework can be very expensive. Poor alignment on a single vessel nozzle can affect the placement of multiple pieces of equipment. The combination of laser scanning and a designer’s knowledge of piping helps assure that the fabricated piping meets design criteria, saving the fabricator potential rework and offering the client valuable quality assurance.
As laser scanning awareness increases, more clients gain knowledge of its capabilities and award repeat work. Time savings, increased safety and highly accurate results are the reasons. We believe that use of a trained designer as part of the laser scanning team, either doing the scanning or overseeing technicians, is a plus in getting usable results. We speculate that the technology will continue to grow such that, eventually, designers will use it like they use tape measures today and that laser scanning will ultimately be part of the design of every project.
LNG liquefaction and regasification takes to the seas—a $27 billion business
Recent years have seen the completion of some major high-profile floating LNG regasification terminals, particularly in the US. Now, after more than a decade of discussion, floating LNG liquefaction is finally being contracted.
Steve Robertson and Lucy Miller, Douglas-Westwood Ltd.
While gas demand remains strong and the construction of onshore LNG projects has experienced substantial delays and cost increases, much attention is being directed to the opportunities arising from the new and potentially groundbreaking floating liquefaction technology market. Floating LNG regasification import terminals are already established. Capital expenditure on FLNG facilities (both liquefaction and regasification) is expected to grow from $695 million in 2008 to just under $8.5 billion in 2015. This article will examine the key market drivers for FLNG liqeufaction, provide an overview of the FLNG import terminals market, and review some of the key enabling technologies. Results are taken from The World FLNG Market Report 2009−2015, published by Douglas-Westwood.
Since the opening of the world’s first floating terminal in 2005, the FLNG industry has grown rapidly and is now a major focus of design, research and investment. Delays to onshore projects, escalating EPC costs, environmental and political issues are all seen as major drivers to the development of this sector. FLNG liquefaction, though still an unproven technology, also offers great potential in the monetization of stranded gas that would otherwise be flared, re-injected or not developed.
Multiphase flowmeter and sampling system yield real-time wellsite results
A new well testing technology allows fluid collection for analysis, determination of fluid properties at line conditions and pinpointing of dry gas properties, all at the wellsite.
Sergey Romashkin, Rospan International; Vitaliy Afanasyev and Vlamir Bastos, Schlumberger
Multiphase well testing is recognized as state-of-the-art technology for metering oil, gas and water streams without needing to first separate phases. It is particularly effective when measuring transient and volume flows for condensate and heavier oils when traditional meters are less effective. Another benefit is easier deployment to harsh, isolated regions, such as the Siberian gas-condensate field discussed here.
A past challenge of multiphase well testing has been an inability to collect representative fluid samples for real-time compositional analysis. However, a new, highly portable system has been developed that allows collection of such samples and then determines fluid volumetric properties at line conditions along with dry gas properties. Combining these properties can minimize uncertainties that often arise when key fluid parameters are not correctly entered in a multiphase flowmeter’s computation algorithm. Basic Pressure, Volume and Temperature (PVT) measurements can be made at the wellsite. This improves the multiphase flowmeter’s ability to compute flowrates.
图4 SPE 115622
Oil market downturn and its effect on the exploration industry
But back orders and momentum are keeping businesses steady. Lessons learned from the last downturn mean that multi-client surveys must be highly funded.
Jeff Moore, Contributing Editor
Having seen the price of oil rise to historic highs and then suddenly plummet to uncanny lows, World Oil wanted to know the impact on the seismic market, particularly newbuild vessels. So we looked at numerous press clippings and corporate reports on the subject from March 2009 back through 2008 and interviewed several industry leaders for their take. Here’s what we discovered.
Remote monitoring and control assist plunger lift
The use of remote electronics to monitor a few key data points allows operators to maximize production and prevent damage to plunger lift wells.
Jim Gardner, FreeWave Technologies, Inc.
Plunger lift is a form of artificial lift used by natural gas producers who experience heavy downhole fluid loads. In many cases, when a gas well produces excessive fluid volumes, the gas pressure of the well is unable to overcome the weight of the fluid trapped inside the tubing. That prevents the well from producing the gas because, essentially, it is blocked by the fluids.
When a well has been blocked by fluids, the common practice has been to manually shut in the well, thus creating downhole pressure. The objective is to build enough downhole pressure to lift the gas. To improve this process, producers use a plunger to assist with lifting the fluid.
Incorporating the plunger is quite effective, but not without its own risks. If the plunger is used incorrectly—such as allowing excessive plunger travel speed—damage is likely to occur to at least the plunger equipment and maybe to other valuable assets.
The manual plunger process also requires management by an experienced operator for optimal results. Technologies that combine plunger control and remote monitoring can free technicians to do other tasks while minimizing the risk of damage to equipment or production and maximizing productivity.
What’s new in artificial lift
Part 2—More developments in sucker rod pumps, gas lift and an innovative cable pump.
James F. Lea, PL Tech LLC; and Herald W. Winkler, Texas Tech University
Continuing our annual artificial lift roundup, this part features more advances in sucker rod pumps, including a small, low-profile unit and a very high-strength sucker rod. A sucker rod service unit is also featured, as one can only go so long between the necessary rod servicing jobs. A rodless, cable-operated pump is also described.
Also featured are new progressive cavity pump designs and a new elastomer for PCPs, as well as a new high-temperature series of PCPs; an RF device that claims to remove scale, even barium sulfate; a downhole gas separator; and seven advances in gas lift, both as an oil producing method and as a gas well deliquification method.
Deepwater GOM discoveries to increase
Julie Wilson, Wood Mackenzie
In 2008, deepwater GOM exploration results suffered a decline for the second consecutive year. Reserves of only 360 MMboe were found, the lowest annual amount in a decade and far below the annual average of over 1 Bboe per year. Furthermore, the number of exploration wells drilled fell for the second year in a row. While success rates at 45% remained high, the discovery rate per well fell to just 12 MMboe—half the 10-yr average. Contributing to the low discovery rate was the high proportion of small discoveries.
Wood Mackenzie believes that deepwater GOM exploration will pick up in the coming years, and 2009 has already seen an encouraging start with three high-profile discoveries made in January. Especially welcome were two discoveries in the Paleogene play.
We believe that the fall in exploration drilling and success over 2007 and 2008 can be attributed to temporary factors. High levels of appraisal and development activity coupled with a tight rig market kept a lid on exploration. An influx of newbuild rigs in the next two years should ease these constraints.
At the same time, there was a shift toward shallower reservoir targets (Pliocene, Pleistocene, Upper Miocene and Middle Miocene), which typically yield smaller finds. The primary driver for this shift was the rise in exploration activity by small independents, which more than doubled their operated wells (to 13 from 6) between 2006 and 2008.
The larger companies more than halved their wildcatting, from 34 wells in 2006 to just 16 wells in 2008. Some of the drop may be due to more appraisal and development drilling. In addition, some larger companies were very exposed to widespread lease expirations in 2007 and 2008, and so those years’ widely-anticipated lease sales received a lot of focus. The highly competitive lease sales of 2007 and 2008 are expected to result in an exploration boost.
Wood Mackenzie’s view remains that deepwater GOM basins are highly prospective with full-cycle economics among the most attractive of all deepwater basins. The range of opportunities available in deepwater GOM—from small, fast-track subsea tie-backs to large, complex, standalone developments—will attract high levels of exploration activity in the future.
Optimizing production in maximum reservoir contact wells
Intelligent completions coupled with an optical downhole monitoring system allow flow control of individual laterals.
Al-Arnaout I. H.,
In today’s drive to improve well production and performance, more innovative methods are continually being implemented to enhance well productivity and reservoir management. By increasing reservoir contact and applying fit for purpose technologies, increased production can be attained at lower drawdown. In multilateral wells equipped with active downhole control valves and downhole measurement devices, monitoring and managing the production from each lateral is achievable. These capabilities enhance well performance and allow better sweep; hence better recovery. This article describes the design, completion, commissioning and operational experience of the world’s first Maximum Reservoir Contact (MRC) well equipped with an intelligent completion, combined with fiber optic monitoring capabilities.
The adoption rate of optical sensing technology for in-well permanent monitoring has accelerated dramatically since it was first introduced more than a decade ago. Today, most of the common electronic-based technology measurements for in-well permanent reservoir monitoring have a commercially available optical equivalent; such as pressure, temperature, seismic and flowmeters. In fact, optical monitoring has exceeded the functionalities of conventional downhole measurement devices. The new fiber optic devices provide various measurement capabilities such as distributed temperature sensing, array temperature sensing and non-intrusive single- and multiphase flowmeters.
The present work involves the use of an advanced fiber optic monitoring system which enables remote monitoring of pressure, temperature, total flowrate and watercut from each of the laterals of a trilateral MRC well. The objective was to use this information to determine the downhole valves’ optimum positions, thereby optimizing production in real-time by:
Monitoring pressure and temperature
Monitoring production allocation from different zones
Identifying production anomalies.
The downhole monitoring system installed in Well A has proved performance reliability and provided satisfactory pressure and temperature data and flow measurement. Present flowmeter technology has a limitation when excessive acoustic noise is encountered. This issue has been assessed and eliminated in the new generation of the flowmeter system. The value of downhole flowmeters is evident in managing multilateral production optimization. Additionally, the flowmeters showed their value when used to detect cross flow during shut-in conditions.
图6表4参8 SPE 118033
Hydrate production and CO2 injection: Two birds with one stone
DAVID MICHAEL COHEN, MANAGING EDITOR, DAVID.COHEN@WORLDOIL.COM
Drilling advances:All eyes turn toward Brazil
LES SKINNER, PE, CONTRIBUTING EDITOR
Last month, Petroleo Brasileiro SA (Petrobras) announced that it was planning to search for new deepwater floaters to develop its massive offshore oil and gas reserves—28 floaters over the next five years. Last year they awarded contracts for 12 floaters. This means there will be at least 40 new rigs working offshore for Petrobras. All this at a time when drilling in the offshore US and the North Sea is down by about 50%! Maybe Petrobras knows something the rest of us don’t. Talk about aggressive!
According to Petrobras, they will need $19 billion in investment to increase production to target levels. Brazil is already producing about 2.8 million boepd. They want to bump that up to 3.7 million boepd over the next three to four years. Funding for the rig purchases will be handled by the Development Bank of Brazil; however, there are delegations in Singapore, South Korea and China to raise capital for Brazil’s production expansion. Petrobras is about to finalize a $10 billion line of credit with China. I’ll bet my hat that they can raise all the money they need.
The Brazilians are doing this right. They are looking past the present government and economic situation to reservoirs that will provide energy for local and foreign markets. They are looking at long-term supply issues, and they are to be applauded for their stand. They’re also leaders in deepwater technology—I’ll bet they were chagrined by Shell’s world record deepwater well at the GOM Perdido project. I’m sure that record will fall soon to Petrobras. The new floaters they are ordering must be capable of working in 3,000 m (9,847 ft) of water. That’s deeper than at Silver Tip. I’ll bet they plan to develop the real deep stuff off the coast of Brazil.
I was once told by a coach that tough times don’t last, tough people do. There must be a bunch of really tough people in Brazil.
ARTHUR BERMAN, CONTRIBUTING EDITOR
Americas. Petrobras has made a light oil and gas discovery with its 6-BRSA-661-SPS (6-SPS-53) “Piracuca” well on Block BM-S-7 in Santos Basin, offshore Brazil. The company estimates in-place reserves of 550 million boe.
BG discovered oil in its 6-BG-6P-SPS, the Corcovado-1 well on Block BM-S-52 in the Santos Basin subsalt play in offshore Brazil.
Noble Energy made a discovery with its MC 519-563 “Santa Cruz” well in the Mississippi Canyon area of the US Gulf of Mexico. The well found 250 ft of oil and gas pay in stacked sandstone reservoirs.
StatoilHydro announced a discovery with its Mizzen well on Block EL1049 offshore Newfoundland, Canada, in 3,600 ft of water about 310 mi east of St John’s, Newfoundland, but no other details were disclosed.
Arcan Resources Ltd., Calgary, made a gas-condensate discovery with its Hamburg 13-29-095-12w6m well in the Chinchaga-Ladyfern area of northwestern Alberta, Canada.
St Mary Land & Exploration made a discovery in the Haynesville Shale play with its Johnson Trust 1-2 well in De Soto Parish, Louisiana.
Europe. StatoilHydro discovered gas with its Asterix Prospect on Block 6705/10 in the Norwegian Sea. Estimated ultimately recoverable reserves from Cretaceous reservoirs are 565 Bcf.
Africa-Middle East. Sonatrach International Petroleum Exploration & Production Corp. (Sipex) made a discovery with its wildcat well A1-65/02 on Block A1-65 Area 65 in Libya.
Lukoil made a gas and condensate discovery on Block A Ghawar in Saudi Arabia. The company estimates about 515 million bbl of oil and 11 Tcfg of recoverable proved and probable reserves from this well combined with an earlier discovery announced in 2007.
Tullow Oil discovered a deeper oil pool in its Tweneboa-1 exploration well on the Deepwater Tano Block, offshore Ghana.
Repsol and its partner OMV made a discovery with their A1-NC202 well in the Sirte Basin offshore Libya.
Repsol-YPF discovered gas with its Anchois-1 well on the Tanger-Larache license block, offshore Morocco. The company estimates recoverable reserves of about 100 Bcf from 427 ft of combined pay from two sandstone reservoir intervals.
Repsol made a gas discovery with its TGFO-1 well on the M’Sari Akabli Block in the Ahnet Basin of onshore Algeria.
Asia-Pacific. CNOOC made two new oil and gas discoveries in Bohai Bay, China.
Oil and gase in the capitals
JEFF MOORE, CONTRIBUTING EDITOR, ASIA-PACIFI
Bangladesh and Myanmar’s E&P row: Implications for the industry
In late 2008, Bangladesh and Myanmar nearly went to blows over an offshore E&P dispute. This small but potentially dangerous altercation has profound implications for the oil and gas industry.
Bangladesh uses 200 MMcf of gas daily, regularly outpacing supply. The per capita GDP is $1,400. Accordingly, E&P is pivotal for the country’s survival. To widen its E&P, Bangladesh on Feb. 15, 2008, accepted 22 bids by seven companies to explore 15 of 28 blocks in the Bay of Bengal.
Myanmar’s gas exports are that country’s top moneymaker. Gas exports to Thailand in 2007 were $2.7 billion, and the country’s per capita GDP is $1,900, so the stakes are high for Naypyidaw as well. Most of Myanmar’s gas discoveries are near Bangladeshi waters. Daewoo leads a conglomerate including two Indian companies (ONGC, GAIL Ltd.) and a South Korean company (Korea Gas Corp.) conducting E&P in these waters.
Bangladesh has long had maritime border disputes with neighbors India and Myanmar, but they have not been violent. India and Myanmar signed bilateral maritime border treaties with each other between 1986 and 1993, and all three countries agreed not to carry out E&P in their disputed waters.
Myanmar and India protested Bangladesh’s 2008 block designation, but not strenuously. At the time, Bangladesh and Myanmar had held high-level negotiations on their maritime boundaries for months.
ARTHUR BERMAN, CONTRIBUTING EDITOR
Papua New Guinea emerging as a natural gas province
In March 2009, InterOil Corp.’s Antelope-1 well in Papua New Guinea (PNG) flowed 382 MMcfd and 5,000 bcpd on a production test (see cover). This may be the world’s highest flowrate for a single well—it certainly set a new record for the island nation that lies 250 mi north across the Coral Sea from Australia. Several giant gas fields have been discovered there since the late 1980s, but the Antelope-Elk discovery opens a new play area in the eastern part of the Papuan Basin. Here, Tertiary carbonate reservoirs are the objective, in contrast to Mesozoic sandstone reservoirs in the western basin area. Antelope and other recent discoveries could make PNG an important exporter of LNG in the near-future.
Open up the US Outer Continental Shelf now!
Whether offshore Alaska or Florida, or off the East or West Coast, the timing, technology and need are aligned to make drilling in these areas a reality.
Katie L. Benko, US Interior Department, Bureau of Reclamation
When the global economy revives, demand for oil and gas will return with a vengeance. The trouble is, while there are ample global supplies, the industry will be hard pressed to bring them into production to keep pace with resurgent demand. The result could well be another oil shock, as Cambridge Energy Research Associates demonstrates in an important study released in March that says almost 8 million bopd are at risk of being deferred or cancelled due to reduced investment and low oil prices.
This means the US industry must act now to prepare for future demand; opening up new areas of the US Outer Continental Shelf (OCS) is critical to meeting that demand. It is also critical to strengthening energy security, reducing oil imports and meeting the global energy challenge.
Government estimates show the enormity of what lies offshore: nearly 100 billion bbl of oil and more than 460 Tcf of gas, enough to heat 100 million homes for 60 years and power 85 million cars for 35 years.
For decades, 85% of the US OCS has been off limits to exploration and production. The moratorium ended last summer, but in Washington the debate continues. This is not responsible government. The economic and security costs are simply too high to justify more debate. US oil imports cost more than $600 billion last year and account for almost two-thirds of the nation’s consumption, exceeding 10 million bopd. The environmental risks posed by E&P, though often cited by opponents, are low. Offshore production technology, science and safety have improved dramatically in recent decades.
How, then, can Washington policymakers reasonably contemplate restricting access to resources that can help address US economic and energy security challenges?