Petrobras sets new pre-salt production record

On 18 May, Petrobras set a new pre-salt production record, with output of 322,100 barrels of oil per day (bpd), 11,000 bpd up on the previous record of 311,500 bpd, set on 17 April.

In addition to encouraging figures for pre-salt production, the company also achieved record output in Espírito Santo, with a monthly average figure of 322,700 bpd, surpassing the previous record set in December 2011.

During May, the production of oil and LNG for all Petrobras fields in Brazil averaged 1.892 million bpd, 1.7% down on the April figure (1.924 million barrels). Including the share operated by Petrobras for partner companies, exclusive oil output in Brazil was 1.942 million bpd. This drop was partly offset by the increasing contribution from pre-salt areas to consolidated output results.

In May, total output of oil and natural gas from domestic fields was 2.267 million barrels of oil equivalent per day (boed), 2.1% down on the previous month. Including the share operated by Petrobras for partner companies, total output was 2.359 million boed.

Added to the company’s output abroad, Petrobras’ total oil and natural gas output in May averaged 2.500 million boed, 2% down on the April figure. The drop in output was due to scheduled maintenance shutdowns on platforms P-25 and P-31, in the Campos Basin’s Albacora field, and on FPSO Cidade de Angra dos Reis, operating in the Campos Basin’s Lula field pilot project.

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EIA report: North American growth helps boost global oil production to record levels

This animated map shows how world crude oil and lease condensate production, measured in millions of bbl/day, has changed since 1980 in key oil-producing regions. Growth in North American crude oil production and recovery in African and Asian markets contributed to a record global production of 75.6 million barrels bbl/day in 2012, according to an agency brief.  Source: US Energy Information AdministrationBy Katie Mazerov, contributing editor

The Middle East still ranked as the world’s No. 1 crude oil producer in 2012, but growth in North American crude oil production and recovery in African and Asian markets, specifically China, contributed to a record global production of 75.6 million bbl/day, according to a brief released on 17 June by the US Energy Information Administration (EIA). Eclipsing the Middle East, it was the strength of the North American, African and Asian markets that drove an overall 2% increase over 2011 levels in global crude oil production, including lease condensate, the brief stated.

In 2012, the Middle East produced 24.1 million bbl/day of crude oil, a basically flat number over 2011 production. Gains in several Middle Eastern nations were offset by declines in Syria and Qatar. Sanctions also contributed to a 17% decline in Iranian production.

This EIA chart shows how crude oil and condensate production has changed year on year since 2007.

The EIA report synthesized recent figures with historical data on regional production trends between 1980 and 2010, EIA analyst Stacy MacIntyre, who compiled the statistics, explained. The data came from the agency’s International Energy Statistics database, with additional trend information compiled from EIA country analysis briefs or other energy briefs published by the EIA, she said.

The former Soviet Union ranked second in global production, with 12.7 million bbl/day, followed by North America, Africa, Asia and Oceania, Central and South America and Europe. Russia, the world’s second-largest crude oil and lease condensate producer, has seen production gains since 2009 due to development of eastern Siberian oilfields, use of advanced technologies and improved recovery techniques in mature fields in western Siberia, and development of a new export infrastructure, the report stated.

In North America, average annual production rose to 12.2 million bbl/day, a reflection of increasing production in unconventional oil plays in the US and rising bitumen and synthetic crude oil production in the Canadian oil sands. North American production had dropped to 10.4 million bbl/day in 2008.

Trends in other global markets reported by the EIA include:

Africa: Recovery of Libyan production was the main driver behind a 6% increase in African production in 2012, to 9.1 million bbl/day. New production in some non-OPEC countries, such as Ghana, also has boosted oil production in the region since 2010. Ms MacIntyre also cited Niger, a landlocked nation in West Africa, as having gone from zero production in 2010 to 20,000 bbl/day in 2012.Asia and Oceania: A 2% decline in oil production in most of the region in 2011 has not recovered, with production remaining at 7.6 million bbl/day. Offsetting that, China, the region’s largest producer, saw production rise after the Peng Lai field in the Bohai Bay was brought back online. It is China’s largest offshore crude oilfield and had been shut down following a spill in 2011. “China’s production declined 0.5% 2011 and grew 1.7% in 2012,” Ms MacIntyre said. “China accounts for 57% of Asia’s production and 54% of Asia & Oceania combined.” Prior to shut-in, production rates at Penglai 19-3 had peaked at roughly 130,000 bbl/day, according to an EIA Country Analysis Brief for China, revised in April.Central and South America: Market contractions throughout the region, notably Brazil and Argentina, contributed to a 1% decline in 2012, following an increase of 3% in 2011. Production in 2012 was 6.6 million bbl/day.Europe: Continued declining production in the North Sea is the primary reason for a downward trend in Europe. Production declines averaged 9% in both 2011 and 2012, in part due to unplanned outages in the UK and a 12% tax rate increase implemented in 2011 by the British government.

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Permanent production packer pushes limits of ultra-HPHT wells

Upper completion technology for as-rolled casing sets new technological boundary at 20,000 psi, 470°F

By James Doane, Guijun Deng, Scott Collins, Gary Anderson, Goang-Ding Shyu, Baker Hughes Inc

Figure 1: While designations continue to change as industry ventures to deeper reservoirs in deeper waters, HPHT is currently defined as 20,000 psi and 450°F and ultra-HPHT is typically considered anything above.

As operators continue to drill in deeper and more extreme formations, the demand for technologies to suit these environments will steadily increase. Great efforts have been made over the years to overcome the hurdles to develop safe and reliable completion tools qualified for conditions in excess of 15,000 psi and 450°F. A new technological boundary was set recently in permanent production packer development – the first 20,000-psi, 470°F permanent production packer for as-rolled casing.

A modified ISO 14310 V3 validation test was conducted on this permanent packer in as-rolled casing ID. The packer passed the test with no visible seal element extrusion, no slip damage, and there were no leaks detected at any of the load points in the test, including a bubble test.

The criteria for designating fields as HPHT (Bellarby, 2009) have been changing over the years. In the past, it was fields with pressure greater than 10,000 psi and temperatures higher than 300°F (Maldonado, 2005). Currently, HPHT designation tends to be at 20,000 psi and 450°F. The term ultra-HPHT is typically used to define well environments that are above 20,000 psi and 450°F.

Design verification (analysis) and validation (testing) for HPHT packers and bridge plugs has generally been in accordance with the ISO 14310 (API 11D1) standard. Specifically for casing conditions, ISO 14310 defines that the packer or bridge plug has to be validated in the maximum ID of the rated casing or tubing sizes and weights.  To meet this requirement, most of the manufacturers tested the packer and bridge plug within a machined maximum casing ID, assuming that maximum casing ID is a reasonably severe casing condition.

However, nuances of a packing element system design may result in pressure containment limits in some systems compared with others when set in an imperfect (out-of-round) casing ID. In-house tests of certain packing element designs indicated that a packer or bridge plug rated according to ISO 14310 standards functioned to higher pressure limits in maximum machined ID casing but was inconsistent in as-rolled ID casing.

Figure 2: For as-rolled casing, geometric imperfection could be due to four types of defects: eccentricity, ovality, thickness and ID size variance.

In other words, the design validation and verification process of a new packing element seal system should include consideration of its ability to conform to expected irregularities since it can be more difficult for a packer or bridge plug to pass the testing in as-rolled casing than in maximum machined ID casing.

Casing ID quality is largely due to irregularities inherited from the casing manufacturing process. First, the geometric imperfection can be categorized by eccentricity, ovality, thickness variance and ID size variance (Figure 2). For as-rolled casing, geometric imperfection (Deng, 2010) could be the combination of these four defects, and the bigger ID profile variation compared with machined casing ID presents the greatest challenge.

A resilient and robust backup system for the rubber seal element has to be well designed to provide 360° support in order to prevent element extrusion. Secondly, the as-rolled production casing from operator’s stockpile can be corroded, and its ID surface is relatively rough (Figure 3). Pits, crevices and other surface defects are often visible in the ID of as-rolled casing.

Figure 3: As-rolled production casing can be corroded and have a relatively rough ID surface. Pits, crevices and other surface defects are often visible in the ID of as-rolled casing.

The objective of the project was to design a packer for 6.625-in., 58.8 to 60.8 lb/ft casing. The packer was rated to pressure from below to 20,000 psi and pressure from above to 17,000 psi at 470°F. Validation testing was conducted with water to all the rating envelope points at 470°F with a cool-down to 300°F and heated back to 470°F. Customer-supplied as-rolled casing was used for testing, in addition to the maximum machined ID casing.

To enhance performance in as-rolled-casing and ultra-HPHT applications, the two concepts considered for the new seal design were:

• The Three-piece Element System, rated to 15,000 psi and 350°F. It has been qualified for applications with a groove up to 0.040 in. deep on the ID of the casing (Humphreys, 2009); and

• The Radially Expanded Element System (Doane, 2012), rated to 15,000 psi and 500°F.

Figure 4 : To enhance performance in as-rolled casing and ultra-HPHT applications, a new seal design combined the best aspects of the Three-piece Element System and the Radially Expanded Element System.

The new seal design combines the best aspects of both designs. The thin metal backup profile from the Three-piece Element System was coupled with the Radially Expanded seal setting action.  The combination resulted in an optimized design (Figure 4) that can be set at higher temperatures and hold higher pressures with improved performance in irregular as-rolled casing.

Slips System

Figure 5 : To reduce development cost and time, finite element analysis was heavily used for design verification and optimization in the development of the ultra-HPHT packer seal for as–rolled casing.

Tangential slips were used to minimize the stress on the casing and packer body. Tangential slips have a large contact area with the casing, which reduces the pressure that the slips apply to the casing. Also, the design of the tangential slip system prevents collapse loads from being applied to the packer body. This design causes the slips to apply a tangential load to the slip seat instead of radial load, which keeps the load off

. Figure 6 : A new production packer was installed in a test cell with customer-supplied as-rolled casing to test if the packer could hold pressure at 20,000 psi at the maximum temperature of 470°F and the minimum temperature of 300°F.

the packer body. A double-grip slip system design will ensure that the seal system movement will be minimal under both tension and compression loads, and therefore the risk of damaging the seal system on as-rolled

Figure 7 : A performance envelope was plotted to show each rating point based on the test results of five load cases.

casing will be decreased.

Other accessories

The packer was designed to minimize the burst pressure on the casing and the collapse pressure on the packer body. A body lock ring between the slips and swage prevents the swage from applying force to the seal with pressure differential above the packer. The pressure above acts on the area from the seal ID to the swage ID to create an axial force on the swage. If there was no body lock ring, this axial force would be applied to the seal, which would apply a radial force on the casing. This radial force would be very high due to the shallow angle on the swage. Instead, the axial force is restrained by the body lock ring.

Material selection and characterization

Perfluoroelastomer (FFKM) was chosen as the rubber material because of its temperature and chemical resistance. FFKM has the highest temperature rating (greater than 450°F) and best chemical resistance of any known elastomer. Since the application for this seal is for the harshest well environments, FFKM is the optimal choice. The compound chosen is stable in oil, amines, H2S, CO2 and zinc bromide. In addition, the compound is stable up to 500°F and is NORSOK-qualified for explosive decompression.

Nickel alloy C-276 was chosen as the material for the seal carrier because of its excellent ductility, corrosion and cracking resistance. The material properties of C-276 at various temperatures, such as room temperature, 250°F and 500°F, have been determined because they are critical data for design optimization

Design verification and optimization

To reduce development cost and time, finite element analysis was heavily used for design verification and optimization in the development of the ultra HPHT packer seal in as–rolled casing (Figure 5).

To be considered as a viable design, the following criteria must both be met:

1. The equivalent plastic strain in the metal should not exceed the maximum allowable plastic strain, and the maximum elastic strain in the seal should not exceed the maximum allowable strain; and

2. The seal must be able to set and withstand 20,000 psi above and 17,000 psi below without packing element extrusion.

Figure 8 : After the validation test to determine if the packer could hold pressure at 20,000 psi at 470°F, the packer seal system showed no visual element extrusion.

The process was repeated until an optimum seal design was achieved, and then a 3-D FEA model was set up to identify the minimum setting force. The 2-D FEA model assumed the casing ID was perfectly round, and the 3-D FEA model took into consideration the as-rolled-casing ID profile with as much as 0.050-in ID variance.

This new production packer (Figure 6) was installed in a test cell with customer- supplied as-rolled casing. The ID profile varied 0.050 in. The variation was due to eccentricity and lobes.  The variation due to eccentricity was 0.020 in., and the variation due to the lobes was 0.030 in. The validation testing was conducted with water to all the rating envelope points at 470°F with a cool-down to 300°F.

Figure 9 : Test results of the permanent packer slips system showed no signs of damage to any of the system components.

Test objective

The objective was to determine if the packer could hold pressure at 20,000 psi at the maximum temperature of 470°F and the minimum temperature of 300°F.

Test load cases

The following seven load cases were tested using water as the medium:

I. Rating envelope point #1 (20,000 psi pressure below with 150,000-lb tension at 470°F);

II. Rating envelope point #2  (300,000 lbs of tension at 470°F);

III. Rating envelope point #3 (17,000 psi pressure above with 175,000-lb tension at 470°F);

IV. Rating envelope point #4 (17,000 psi pressure above with 300,000-lb compression at 470°F) and temperature cycle (470°F-300°F-470°F); and

V. Rating envelope point #5  (20,000 psi pressure below with 300,000-lb compression at 470°.

In addition to the testing outlined above, a nitrogen test was conducted on load case I and V.

Test results

A performance envelope was plotted (Figure 7) based on the test results of the five load cases.

At the end of the test, the test fixture was disassembled. The casing was cut open to remove the packer. Figure 8 shows the tested seal unit after the test. No visual element extrusion was identified on the seal element and seal insert.

Figure 9 shows the packer slip system after the test. There was no damage to any of the packer slip components after the test.

A major milestone in upper completion technology has been achieved. For the first time, a permanent production packer was successfully built to seal a pressure of 17,000 psi from above and 20,000 psi below at both 300°F and 470°F in as-rolled casing.

This article is based on a presentation at the 2013 International Petroleum Technology Conference, 26-28 March, Beijing.

References

Bellarby, J., Well Completion Design. 2009, 1st edition, Elsevier, Amsterdam, p. 639-641.

Deng, G., Shyu, G, “An Innovative Approach to Optimizing Design of HP/HT Well Tubular Strings,” SPE 132550, 2010 SPE ATCE, Florence, Italy, 19-22 September 2010.

Doane, J., Deng, G., Collins, S., “A Completion Technology Milestone – The First 25,000-psi 500°F Packer Seal System,” SPE 159182, 2012 SPE ATCE, San Antonio, 8-10 October 2012.

ISO 14310: 2008, Petroleum and Natural Gas Industries – Downhole Equipment-Packer and Bridge Plug.

Maldonado, B, September/October 2005, “Special Design Strategies Vital as HPHT Completion Edge Towards 500°F, 30,000 psi.” Drilling Contractor, Proc. SPE/IADC Drilling Technology Conference, Aberdeen.

Humphreys, A., Ross, R, “Delivering a Fully Qualified HP/HT Production Packer Following Field Failure,” March 2009 SPE Drilling & Completion.

Shyu, G, “Review of the Application of FEA to the Development of WL and Premier Packer,” MSC Software 2007 Virtual Product Development Conference.

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50% of total production to be pre-salt by 2020, Petrobras says

Petrobras has cut its average drilling time by approximately 50% since 2006 to around 70 days per well in 2012, Carlos Tadeu da Costa Fraga, executive manager for Petrobras, said during a luncheon at the 2013 OTC.

By Joanne Liou, associate editor

Recounting Petrobras’ history in pre-salt activities so far, Carlos Tadeu da Costa Fraga, executive manager for Petrobras, shared the company’s strategy to accelerate the transformation of discoveries to producing fields. In 2012, its pre-salt production made up 7% of the company’s total output, Mr Fraga stated at the 2013 OTC in Houston on 7 May. “We expect to have 42% of production coming from pre-salt in 2017 and 50% of the total production coming from the pre-salt in 2020.”

Petrobras’ pre-salt exploration of the Santos Basin began in 2000 and 2001 with the acquisition of the Santos Basin pre-salt blocks, drilling the first wildcat well in 2005. In 2006, the company made its first major discovery with the Lula field, and by 2010, Petrobras had declared commercial production from that field. Drawing a comparison between the Campos and Santos basins, Mr Fraga noted the sizeable volume being discovered in the Santos Basin in a relatively short amount of time. “The Campos Basin took us 23 years since the first discovery to have the current assessment that we have regarding the volume of oil and gas in place,” he said. “In pre-salt, just after the first four years of exploration and after the first discovery, we’ve reached the same point in oil and gas assessment.”

Although it took Petrobras a much shorter timeline to explore and assess the Santos Basin than Campos, Mr Fraga noted that the strategy used was the same for both areas. “First is a very intensive appraisal step to understand the reservoir and to come up with the proper and responsible decision after we learn about the area.” In the Santos Basin alone, up to the end of 2012, Petrobras had drilled 60 wells, run 41 drill stem tests and cut approximately 4,900 ft (1.5 km) of coring. The company had run 72 conventional logs and 57 production logs during wells tests.

Production numbers indicate the company’s success, with its approximately 300,000 bbls/day of production expected to reach more than 1 million bbls/day by 2017 and more than 2 million bbls/day by 2020. “It’s possible, but it’s going to demand a lot of energy and work,” Mr Fraga said. “I’m very confident we are going to do it. We need to count on you all to have those projects in on time and on schedule and on cost,” he told the OTC audience.

Mr Fraga referred to innovation acceleration – technological development from geological models and flow models, well technology and subsea equipment, which is key to ramp up production. “As we have a very sizeable area, as we are going to have long-term performance, we want to be able to accommodate any new technology that may come in the future,” he said. Petrobras also is working to reduce its drilling costs, which represent approximately 50% of its capital expenses in pre-salt. The current average drilling time for a well is already 50% less than the average time of 143 days in 2006. “We are drilling wells around 70 days,” Mr Fraga said. “Last week we finished a well in less than 40 days.”

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Fit-for-purpose rigs, unconventionals drive Statoil production goals

By Joanne Liou, editorial coordinator

Statoil is directing its fit-for-purpose rig fleet and technology strategy to help reach a production goal of more than 2.5 million boe/day by 2020, up from 1.9 million boe/day in 2010. Noting recent successes in increasing the average oil recovery rate from Statoil-operated fields from 49% to 50%, the company wants to push that percentage even higher, Karl Johnny Hersvick, Statoil senior vice president of technology excellence, stated. The company outlined its growth strategy in a series of press conferences at the 2012 OTC last week in Houston.

Jon Arnt Jacobsen, chief procurement officer at Statoil, and Oystein Arvid Haland, senior vice president drilling and well, discussed their company’s shift from fixed platforms to using mobile rigs to drill subsea wells. In collaboration with Aker Solutions, Statoil’s Category B rig is under construction, with delivery of the first unit expected in the second half of 2015. The rig design fills the gap between light intervention vessels (Category A, which has been in operation since 2003) and conventional rigs (Category C), according to Statoil. The rig is designed to improve oil recovery, and its design has been optimized for heavy intervention and light drilling in existing wells.

A Category D rig, targeted for mid-water production operations, also is under construction and expected to be delivered in 2014 to 2015, while Category J is designed for shallow waters and harsh environments. The latter is expected to be delivered in 2015 and will provide 20% more cost-effective well construction.

Statoil’s developing rig fleet is compounded with the company’s focus on four areas: seismic imaging and interpretation, reservoir characterization and recovery, efficient well construction, and a “subsea factory.” The subsea factory project involves the development of the Åsgard subsea gas compression by 2015 and acquiring all the necessary elements for a subsea process facility on the seabed to accelerate production. “Our mission is that technology connected to (reservoir recovery) will contribute to increase an additional 1.5 mboe/d by 2020,” Siri Espedal Kindem, senior vice president of research and development, said. “Just as important is a step-change in well construction efficiency. We have a clear ambition ahead to reduce the time we spend on well construction by 30% and 15% in spending.”

Statoil currently has about 3,000 employees working on 300 increased-oil-recovery projects. In August, the research and development division will become the research, development and innovation division, Mr Hersvick stated. “It’s a concrete measure to get our hands on more good ideas, to push recovery rate even further. We cannot compete with supermajors of this world when it comes to funds and resources, but we can and we will compete when it comes to innovation.”

Statoil expects 12% of its portfolio to come from North American unconventionals by 2020, Torstein Hole, senior vice president of development production North America – US onshore, said.

Moving onshore, Statoil expects 500,000 million boe/day to come from North American unconventionals by 2020, Torstein Hole, senior vice president of development production North America – US onshore, said. The company’s strategy for growth in US shale plays is founded in its presence in the Marcellus, Eagle Ford and Bakken, with the Eagle Ford paving the way for Statoil’s operatorship. Statoil entered a 50/50 joint development agreement with Talisman in 2010. With 165,000 net acres and 12 rigs currently drilling, the play has produced about 640 million boe to date. Statoil is positioned to become operator within that play by the end of 2013.

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Geothermal Energy Production - Connexus

Today, there is more interest than ever in geothermal power. A 2010 report by the Geothermal Energy Association called “Geothermal Energy: International Market Update” states that both the number of countries producing geothermal power and the total worldwide geothermal power capacity under development appear to be increasing significantly.

The report found that between 2005 and 2010, Germany was the fastest growing geothermal power producer in the world with a whopping 2,774 percent increase in installed megawatt capacity.

Increased awareness of “clean” energy to reduce CO2 emissions, concern over continued world oil production and rising costs of energy exports are all helping to expand Germany’s renewable energy market. But perhaps the biggest driver powering the growth is the country’s Renewable Energy Sources Act—a very ambitious plan to replace 30 percent of the total electricity consumption in Germany with renewable energy by 2030. By 2050, the goal is 60 percent.

Germany announced its new energy goals at the end of the last millennium and today is one of the leading industrial nations in the renewable energy sources sector, according to the country’s Federal Ministry for the Environment, Nature Conservation and Nuclear Safety.

Helping fuel this trend toward climate-friendly energy are government incentives in the form of grants to industries and universities to research and develop enhanced geothermal technologies, and 20-year fixed feed-in tariffs to power plant operators that give priority to electricity that comes from renewable energy sources, such as geothermal—making higher risk and higher cost projects more feasible.

This increase in geothermal drilling and production has made geothermal the fastest growing business for Baker Hughes in continental Europe. Plus, with the Baker Hughes Center of Excellence for geothermal and high-temperature research and development in Celle, Germany, the company is well positioned to support the growing demand for products and services, as well as the government’s ambitious target.

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Baker Oil Tools' EXPress<font size="-1">^™</font> Expandable Screen System Enhances Sand Control and Production

HOUSTON (Feb. 26, 2003) – The EXPress™ Expandable Screen System, now available from Baker Oil Tools, is a premium downhole sand exclusion device with a unique combination of mechanical advantages. The EXPress screen combines the proven sand control ability of the Baker Oil Tools EXCLUDER screen with the additional benefits of screen expansion such as annular flow reduction, hole stability, and large inside diameters.

The EXPress Screen's design, based on perforated pipe expansion technology, adds tremendous mechanical strength and reliability to the screen. The EXPress screen can be expanded outward to greatly reduce or eliminate the annular space between the wellbore and the screen. Reduced annular flow lessens the potential for sand migration and development of "hot spots" in the screen. The screen's unique filter membrane construction allows for the production of mud solids without plugging the screen while still maintaining effective sand exclusion.

Baker Oil Tools has published a brochure detailing the unique advantages of the EXPress Expandable Screen System.

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