Laboratory supervisor Mardônio Cruz Gonçalves Filho conducts a thickening time test of a cement slurry at Baker Hughes’ Laboratory of Cementing and Stimulation in Macaé, Brazil. Competition is high in the country for qualified personnel to meet the needs of a growing E&P industry.

Expansion projects under pressure as companies face shortage of experienced natives, local content laws

By Katie Mazerov, contributing editor

Poised to become the largest single offshore market in the world, Brazil is undergoing a major boom cycle, with multinational operator Petrobras leading the way. The company has a reported investment of more than $224 billion over the next five years. It also announced earlier this year that it had awarded seven contracts for newbuild deepwater rigs to Brazilian shipyard Estaleiro Atlantico Sul (EAS) and was in the bidding process to award 21 more.

The aggressive program is in line with Petrobras’ 2008 announcement to add 40 newbuilds to its fleet; bids for 12 were previously awarded to existing drilling contractors. Bolstered by the massive presalt discovery in 2006, Brazil’s oil production is expected to exceed 5 million bbl/day by 2020.

“I don’t doubt the ability and willingness of Petrobras to move ahead with its plans,” said John Keller, vice president and oilfield services research analyst at financial services firm Stephens Inc. “Rigs currently deployed are targeting less than 30% of the country’s identified offshore reserves, which would imply potential for a lot of growth going forward. It will be measured growth but still favorable for 2012.”

The offshore industry is stimulating the entire Brazilian economy, with major operators and services companies establishing centers of operation.

But with that growth comes a host of challenges. “There are a multitude of forces at work in Brazil,” said Nicholas Stocker, regional director, Latin America for NES Global, which provides engineering services and specialist staff support for the energy industry worldwide.

The Baker Hughes Rio Research and Technology Center is an advanced applications engineering and research facility located in the Technology Park of the Federal University of Rio de Janeiro, close to Petrobras’ Cenpes facility.

Effects of expansion

NES Global’s clients in Brazil have been requesting personnel in the hundreds rather than tens, an indication of how stimulated the market is. “The effects of the expansion are being felt all along the supply chain, from servicing vessels and oil service companies, and for operators potentially partnering with Petrobras,” he said. “Placed alongside Brazilian president Dilma Rousseff’s Accelerated Growth Program, which is looking at massive infrastructure improvements in terms of highways, rail lines, power generation and water management, it is all pointing to a serious lack of engineering expertise in the country.”

Add to that stringent local labor practices, local content laws governing the importation of workers and a cumbersome work visa program, the pressures placed on the manpower needs are only increasing. “Brazil is traditionally an agricultural country with great disparities between rich and poor,” Mr Stocker said. “But it has become a melting pot of challenges and opportunities.”

Stringent labor laws governing minimum-wage workers place significant social costs on companies looking to hire local workers for the anticipated ramp-up in business. “An employer will pay an extra 70% on top of an individual’s salary to employ him under Brazilian labor law,” Mr Stocker explained.

At the same time, local content regulations, governed by Brazil’s National Agency of Petroleum (ANP), require that a certain percentage of a project be serviced by Brazilian companies, from the shipyard down the entire chain. Companies that bring in experienced workers from abroad pay hefty importation-of-service taxes as high as 51%. In addition, work visa processing times can take up to 40 days.

Shortage of engineers

The local content stipulations are having the added impact of making delivery of major projects challenging in terms of both time and quality, in part because of the ratio of low number of local engineers to project needs, Mr Stocker explained. As an indication, while Brazilian universities graduate 40,000 engineers per year, China and India each graduate well over 100,000. Project delays necessitate importing more expertise, which then impacts profit margins.

From a fabrication standpoint, rig and platform production delays have been as long as 5 months to 17 months. However, local shipyards are proving their ability in ongoing construction projects for eight new rigs, Mr Stocker added. “The local content laws versus the shortage of engineering capability locally and massive demand make this a complex scenario,” he said. “For every person outsourced, the cost is roughly 2 to 2 ½ times the salary of a local hire. The country is going to have to graduate more engineers, but they will need to quickly gain the experience required for working in the ultra-deepwater fields of Brazil.”

In the meantime, Mr Stocker foresees reviews on existing regulations, and lobbying efforts calling for a relaxation on some importation service charges for high-level technical engineers with specific skill sets to keep projects on track.

Oil sector reforms that govern the huge presalt provinces are bogged down in the Brazilian Congress. Of concern is the issue regarding the 30% stake Petrobras will have to hold in each project, Mr Stocker said. Some in the Brazilian government want to ensure that Petrobras retains operator status in all presalt projects.

Wilson Lopes, Baker Hughes

“For operators partnering with Petrobras, that would mean a lower stake in some very lucrative projects, sharing in the production costs with reduced return,” he explained. Other oil industry insiders believe that, unless the government moves to attract foreign investment, Petrobras could become overextended financially and won’t be in a position to get projects on track.

Baker Hughes, which has an office in Rio de Janeiro and its operational hub in Macaé, is seeing market challenges for personnel and equipment. The market growth is very attractive for foreign companies on the leading edge of technology, including major service companies, as well as smaller players, said Wilson Lopes, geomarket sales director for the company’s Brazil region.

Unprecedented growth

“The country is undergoing a significant growth trend, unlike anything seen here before,” Mr Lopes said. “This is a highly demanding environment that is requiring technical leadership. The challenges of the pre-salt discoveries, which are in ultra-deepwaters and up to 300 km off the coast, will push the technology to new limits. From a technical standpoint, this environment is more challenging than the Gulf of Mexico. That translates to attracting the right people from various sectors of the industry and training them so they are ready and able to support the level of activity.”

Baker Hughes has more than 2,000 employees in the country, a mix of local workers (94%) and imported technical specialists. “There is significant competition for qualified personnel,” Mr Lopes said. “The fact that the operators also have a gap in human resources makes the situation even more difficult.”

Worldwide demand for equipment and tools, especially in other deepwater markets, will make that situation very competitive if growth rates continue at their current rate. “Right now, we are supporting about 25 offshore rigs, and we’re expecting that number to increase 20% over the next 12 to 18 months. We are investing in rental tools and equipment,” Mr Lopes said.

Companies are putting resources toward plans to ensure operational and cost efficiency, development of technology, infrastructure investments and well testing, Mr Lopes said. “There has been a major effort by all companies involved, including Petrobras, to push this prospect forward,” he noted. “Day by day, we are seeing significant research and development of technology on the production side to apply what we know to lower the risks and make this challenging arena an attractive prospect.”

Among other initiatives, this year Baker Hughes inaugurated the Rio Research and Technology Center (RRTC), an advanced applications engineering and research facility located in the Technology Park of the Federal University of Rio de Janeiro, close to Petrobras’s Cenpes facility. It will eventually house more than 100 scientists and technicians when fully operational.

A well test an development facility was also opened this year in Macaé, designed to test electrical submersible pump (ESP) systems prior to installation. ESP technology is crucial for enhancing production in the ultra-deepwater and heavy-oil reserves, Mr Lopes said. The facility has capabilities for system integration tests and simulation for ESP systems capable of handling up to 86,000 bbls/day of fluid and maximum surface pressures of 5,000 psi. The facility’s control room displays real-time data, including flow rates, temperature, torque, pressure, vibration and electrical parameters.

By Jeroen Nijhof, BP Norge; Tom Rune Koløy and Kristian Andersen, Halliburton

Figure 1: For BP’s Valhall redevelopment, a new swellable packer design was developed to handle a maximum differential pressure of 10,000 psi for propped fracturing across the packers. The design features a proprietary end-ring system and special elastomers to increase the working envelope of the packers, where the swelling elastomer is confined between backup rings and yields better performance.

To redevelop the Valhall Field in the North Sea to enable continued production until 2050, BP Norge is increasing the reservoir pressure by waterflooding. To protect the field from associated damage and minimize cost in the next phase of production, different strategies were evaluated, including the application of swellable packers (SEPs).

The operator wanted a zonal-isolation method that would leave the annulus void of cement. All producing wells on Valhall are stimulated with proppant fracs; hence, the open-hole zonal isolation between the zones must be capable of withstanding high differential pressure during stimulation and in case of screen-out. Oil-swelling SEPs were identified as a potential solution.

Full-scale testing was done under the conditions that would likely be experienced in the field.

Additionally, to reduce the uncertainties associated with water injection and mitigate their consequences, a decision was made to include capabilities to monitor flow between reservoirs and wells and to enable control of this flow. This led to the development and qualification of high differential pressure (∆P) SEPs for a particular application in prop fracture stimulation in Valhall production wells.

Qualification

The requirements in Valhall call for a maximum differential pressure of 10,000 psi for propped fracturing across the SEPs. In addition, the SEPs have to withstand a long-term differential pressure of 4,000 psi during production. The SEPs would require a high-pressure sealing capacity and be capable of withstanding a wide temperature variation.

During the test, a critical requirement was to establish the pressure at which the oil-swellable packer would fail and determine how it would react to the type of temperature cycling that would be experienced.

Centralizers would be used to ensure an even swell in the packer when deployed in the horizontal well section and to provide stand-off for the packer while running in hole.

Solids-laden, oil-based mud would be used to drill the reservoir section, and the SEP would use this as fuel to swell and provide the high-pressure seal.

An 8.5-in. open hole is typically drilled through the reservoir, followed by the installation of a 5.5-in. liner. The SEP was to be designed with the same ID as the 5.5-in. pipe to seal inside the 8.5-in. open hole. Following are the details of the conditions that prevailed.

Producer wells

• Maximum differential pressure for propped fracturing is 10,000 psi (tip screen-out: 12,000 psi to 13,000 psi at liner with reservoir pressure of 3,000 psi).

• Maximum long-term differential pressure is 4,000 psi (6,000-psi injection finger with 2,000-psi bottomhole foundation pressure).

Injection wells

• Maximum differential pressure for hydraulic unpropped fractures is 3,000 psi to 4,000 psi.

• Long-term differential pressure is similar, with intra-zonal pressure of 3,000 psi to 4,000 psi.

General

• Reservoir pressure is 2,700 psi to 4,000 psi.

• Reservoir temperature is 95ºC, bubble point 3,350 psi, gas/oil ration is 914 standard cu ft per stock tank barrel.

• Fracture fluid temperature is 20ºC.

• The hole drilled is 8.5-in., but the SEPs need to cope with potential washouts of up to 9.5 in.

Other design considerations for open-hole zonal isolation are:

• Frac tip screen-out pressure;

• Strength of chalk formation;

• Open-hole/run-in-hole constraints; and

• Acceptable leak rates past zonal isolation.

Suitability

When designing SEPs for dynamic downhole conditions, it is critical that the SEP be designed with the capability to hold the expected differential pressure, considering the cool-down experienced during stimulation or injection.

Compared with mechanical packers that will be ready for fracking after they have been set, SEPs require time to swell and to build up internal swelling pressure before they are ready for fracturing to commence. Depending on the design and required differential pressure, this can range from less than a day up to weeks.

SEPs can be designed with a continuous 30-ft long element, ensuring optimal coverage in fractured and washed-out formations. Long elements also offer additional anchoring forces over a shorter packer to prevent liner movement in dynamic downhole conditions.

Further, SEPs remain flexible for the life of the wells, being able to swell in the wellbore fluids if washouts or borehole breakouts occur in the packer-setting area over the life of the well.

In stimulation applications, SEPs also exert minimal stress on the borehole during setting. Exerting significantly higher stresses on the borehole during setting can result in fracture initiation points near the open-hole packer.

Elastomer, packer design

Various types of swelling elastomers have been developed for different applications and downhole conditions. Elastomers that swell in either hydrocarbon or water are dominant, but some types will swell in both media. During well planning, the well, formation and fluid properties are evaluated to select the appropriate elastomers and the appropriate SEP design.

Two main categories of SEPs exist – bonded-to-pipe packers and slip-on-type packers.

On bonded-to-pipe packers, the swellable elastomer element is chemically bonded onto casing or tubing that will run in the well. For slip-on-type SEPs, the swellable elastomer element is manufactured as a sleeve that can be installed on the casing/tubing in the pipe yard or at the rig site. Bonded-to-pipe packers typically are used where higher differential pressure is expected or where there is a need for a long sealing element because of hole/formation conditions.

Based on testing and field experience, metal end rings are used on all SEPs on both sides of the swelling elastomer element to protect, centralize and guide the SEP assembly while it is run in hole. The rings also limit the extrusion gap available to the swelling element of a set SEP, for increased differential pressure capability.

Several tests had been conducted to qualify an SEP to 10,000 psi for the Valhall application, but none had been successful. A new type of SEP design was developed featuring a proprietary end-ring system and special elastomers to be deployed against the formation – resulting in an SEP system where the swelling elastomer is confined between the backup rings. This increases the working envelope of the SEP.

Based on in-house testing of the new design, a packer design was created to hold the required 10,000 psi during fracturing stimulation operations with the associated temperature changes. It was built on 5.5-in. base pipe with a 5 meter-long rubber element and an OD of 8.2 in.

As this new design had been subjected to only limited testing, there was a risk of packer failure early in the test program. To minimize this risk, two packers were tested in series. The test was set up to perform the pressure test across the individual packers, as well as the whole two-packer system.

Figure 2: A custom-made fixture was set up to qualify an SEP to 10,000 psi for the Valhall application. External and internal sensors controlled the temperature while three pressure transducers monitored the pressure.

Test setup

A custom-built test fixture was designed to be 690 bar/10,000 psi (Figure 2).

The test was set up with two 5-meter swellable packers in series. Two high-pressure pumps were connected to the test fixture; one at the HP side and one between the packers. The cooling was performed by flowing water through the base pipe from the HP side to LP side.

Three pressure transducers monitored the pressure while external and internal temperature sensors controlled the temperature. All transducers and sensors were connected to a real-time logging system.

Cooling effect on SEPs

Pressure has always been one of the main parameters for any SEP design, but for a stimulation application, the impact of temperature on the differential-pressure behavior of the SEP must be taken into account. Proper estimation or description of the downhole conditions, therefore, is crucial to the design. As with any material, the swellable elastomer element of the SEP will contract during a drop in temperature.

The thermal expansion/contraction of the elastomer is approximately 10 times larger than the coefficient for steel. This means that, with increasing temperature drop, contraction effects will be more severe. The contraction will lead to a drop in internal element pressure; ultimately, it will result in a physical shrinkage, and the pressure seal will be lost.

To be able to link the temperature drop to SEP performance, laboratory and full-scale tests have been performed. Results show that an SEP can handle a certain temperature drop if given sufficient time to swell. However, the differential pressure holding capacity is reduced if the temperature drop is too large to handle at that particular point in time.

From the experiments, it is possible to quantify the additional amount of time required to allow the SEP to build up sufficient internal pressure so that the temperature drop does not affect the performance of the SEP. Therefore, it is critical to use accurate input numbers and a realistic model to predict the temperature drop that the packer will experience.

The engineering/service company developed an SEP design simulator to accurately predict the working envelope of SEPs in hydraulic fracturing and injection applications.

In these tests, two approaches were made to simulate hydraulic fracturing:

• Cool-down based on steady-state heat conduction. After infinite time of pumping, the temperature in the SEP will reach a steady state regardless of the amount of fluid pumped. This is based on constant heating from the reservoir and cooling from the frac fluid inside the tubing.

• Full cool-down of the packer and reservoir. Temperature dropping from 95°C to 20°C, where 20°C is the estimated surface temperature of the fracturing fluid.

Piston effect

During the testing in tandem of the two packers, a piston effect was seen. As pressure increased on the HP side, the elastomeric element on the first SEP flexed toward the collar. This led to a pressure build-up between the two SEPs inside the autoclaves. On the pressure charts, this can look like a leakage over the first SEP.

Test data

The two packers were exposed to more than 65 days of testing – to extensive temperature cycling, high differential pressure and rapid bleed-off, both controlled and uncontrolled. The packers did not fail. At 64°C and 95°C static temperatures, 690 bar/10,000 psi differential pressure was achieved on each of the single 5-meter packers.

Swelling of the packers

The swelling of the packers commenced on 14 January, when oil-based mud was pumped into the autoclave and the heating was switched on at 95°C. The mud circulated for the first 48 hours to simulate the running-in-hole operation from the LP side to the HP side. In addition, the second packer, and especially, the end ring on the LP side, was more or less centralized since the packer was fastened to the autoclave end cap. Two centralizers were used on the HP side and between each packer.

Time to seal was verified with the HP pressure pump on day three. In preparation for the test, the behavior of the packers had been estimated. Although the BP requirement of the test was achieved – 10,000-psi differential pressure capability within 45 days, the estimated 13 days to 690 bar/10,000 psi was not achieved.

Figure 3: A design method was established for swellable elastomer packers in hydraulic fracturing without total cool-down. Among other assumptions, the method assumes that there are no cooling effects at the ends of the rubber element.

The packers were treated during the pressure build-up, meaning that pressure increases were done at a slow rate in agreement with BP. In addition, delays were experienced that resulted in a relatively slow time to reach the 10,000-psi pressure rating.

If the same trend from day three to day nine is linearly extrapolated, it will take 27 days to reach 690 bar/10,000 psi. This is a more realistic time to maximum differential pressure in these conditions.

Cool-down effect

A design methodology was established for swellable elastomer packers in fracturing operations (Figure 3) based on three main assumptions:

• Steady-state heat conduction through the rubber element;

• No cooling effects at the ends of the rubber element; and

• Tubing/liner wall is at fluid temperature.

Figure 4 represents the temperature profile in the packer and the average rubber element temperature. This temperature profile applies for fracturing operations where pumping times are limited to days.

Based on the above equations and well information from Valhall, the following were calculated:

• The average rubber element temperature T_avg is 64°C; and

• The temperature drop, ΔT, is 95°C – 64°C = 31°C.

For fracturing operations where pumping times are limited to days, the cool-down effect on the formation is not significant, and the profile in Figure 4 would apply. Figure 5 shows the temperature profile through the swellable packer with the dimension used in this test during a fracturing operation. When cold fluid is injected for long intervals (for example, water-injection wells), there might be a near-wellbore cool-down effect resulting in a lower temperature at the element/wellbore (EWB) interface.

Flowing water at 6°C simulated the fracturing process for two hours from the HP side to the LP side through the 5.5-in tubing. The packer was then pressure-tested until leakage. Because of the test setup, the first packer was also exposed to cold fluid at the end of the rubber element on the HP side, resulting in a severe situation.

Figure 5: This temperature profile shows that when cold fluid is injected for long intervals, there may be a near-wellbore cool-down effect, resulting in a lower temperature at the element/wellbore (EWB) interface.

The cool-down process was repeated two times; the first time after 35 days and the second after 42 days. In the first cool-down, 280-bar differential pressure was achieved and the pressure test stopped before leakage occurred, indicating higher capability than 280 bar.

In the second test, 592-bar maximum differential pressure was achieved, and there was a small leakage to LP side. Several comments can be added:

1. After two hours, the water flow was stopped, and Clairsol NS replaced the water. The change took time, which meant the temperature in the test fixture increased before pressurizing of the packers started. The pressurizing can be seen as small drops in temperature on the internal HP side. The temperature of the Clairsol NS was about 20°C.

2. The temperature over the packers was constant at 95°C, indicating that fracturing will not influence the temperature at the EWB interface.

3. Temperatures at the internal and external high-pressure side were dropping when the water started flowing and stabilized at 15°C to 25°C.

4. Water-flow first test: 40 to 50 liters/min. Water-flow second test: 11 to 50 liters/min. The water supply in the lab during the second test was fluctuating for an unknown reason, which resulted in a higher external temperature at the HP side.

5. The temperature sensor that controlled the heating pads at the collar was changed from external to internal, from the first test to the second test. This resulted in heating on the collar and an almost zero temperature drop internally at the collar in the second test.

Full cool-down

In the full cool-down approach, it is assumed that the reservoir will obtain surface fracturing fluid temperature; i.e., 20°C. This approach is regarded as the most conservative since the swellable packer will see a larger temperature drop, from 95°C to 20°C, and therefore, it was expected that the differential pressure capacity of the packers will be lower. The main reason for this is that a larger temperature drop will induce a larger contraction of the rubber element and therefore a lower internal element pressure against the formation.

In this test, the full cool-down was simulated by lowering the temperature from 95°C to 20°C. The test fixture was then left to cool down. This process was performed two times; the first after 44 days and the second after 57 days. The first time, the test fixture was left to cool down for four days, and the second time for seven days.

From the test, it can be summarized that the first packer started to leak around 150 to 200 bar, and the second packer started to leak around 300 bar to 370 bar, stabilizing at 320 bar.

Pressure logs from the pressure testing of the second full cool-down show:

• The first packer started to leak around 150-200 bar;

• The second packer started to leak at approximately 630 bar;

• The pressure at the LP side was bled off. 690 bar was reached without leakage to the LP side. After several attempts to obtain stable pressure, a small leakage to the LP side was obtained;

• There were rubber particles in the return fluid when bleeding off pressure; and

• Obtained differential pressure was higher because of longer swelling time in combination with earlier performed temperature cycles.

Differential-pressure capacity at 64°C and 95°C

As part of the reheating step, one differential pressure test was added to gather more data from the test. The T_avg = 64°C was chosen as the test temperature.

After 690 bar/10,000 psi was reached over the total system, the pressure at the collar was bled off in steps down to zero to verify 690 bar/10,000 psi differential pressure over the first packer. Since higher differential pressure was achieved at 64°C, the cooling of the side of the packer could have had an effect. In addition, the longer swelling time will influence the results. The test was performed at day 35 and day 42 while the 64°C test was done at day 51.

During the bleed-down, it was noticed that the return fluid contained small rubber particles, also visible on the pressure log from the collar.

When the pressure on the HP side bled off, the end rings could be heard moving in the autoclave. Calculations indicated that the 9 ⁷/8-in. casing would increase its length at maximum load (690 bar/10,000 psi) by approximately 23 mm while the 5.5-in. tubing would be compressed by approximately 15 mm. When the pressure is bled off, the casing and the tubing will relax, and the end rings will move back approximately 8 mm.

690 bar/10,000 psi was also reached when the system was reheated to 95°C. The second packer was holding more or less all the differential pressure, and after holding 690 bar over the system for a period of time, the pressure on the collar was increased. This was done to verify 690 bar differential pressure capacity over the second packer.

Table 1: The distribution of differential pressure over the first packer and the second packer shows that each packer’s behavior was almost equal until the 64°C/147°F test on day 51. After that, the second packer was holding nearly the total differential pressure, indicating that the first packer was damaged during the 64°C/147°F test.

Differential pressure distribution

Table 1 shows the distribution of the differential pressure over the first packer, second packer and the total differential pressure over the entire system. Until the 64°C (147°F) test, the behavior of the packers was almost equal. After that point, the second packer was holding more or less the total differential pressure. This indicates that the first packer had been damaged during the 64°C test.

Overall, the first packer experienced the worst conditions during the test, during both swelling and pressure testing.

Failure mode

The two packers were exposed to 65 days of testing. They have seen:

• High differential pressure in combination with large temperature variation;

• Compression and expansion forces of packers and test autoclave during pressurizing and bleed-off – approximately 8 mm of movement. Most of the movement was seen on packer 1; and

• Rapid bleed-off.

After the 64°C/147°F test, rubber particles appeared in the return fluid when bleeding off, mainly from the HP side and collar.

To investigate the failure mode of the packers, the casing was to be split open. Two approximately 1-meter elements of the test fixture with the packers inside were split open to investigate possible mud channels between the packer OD and the ID of the casing and packer failure mode. During splitting of the second packer, the compression force in the rubber was so high that four saw blades became stuck and were broken. An angle grinder was used to cut through the test fixture and the second packer.

These observations were made:

• Packer 1 was damaged with a failure channel going through the length of the packer on the top side of the casing. The rubber element was held in place by the backup rings.

• Packer 2 was virtually undamaged. There was an indication of a failure channel on the HP side, but it did not go through to the LP side.

• A thin layer of mud was covering the inside of the 9 ⁷/8-in. casing. No clear pressure channels were visible either on the surface of packer or the ID of the casing. The 5.5-in. tubing was still half-filled with mud through the length although the pipe had been flushed with water for several hours.

Figure 6: Two elements of the test fixture with the packers inside were split open to investigate possible mud channels between the packer OD and the ID of the casing and packer failure mode. While splitting the second packer, four saw blades became stuck due to the high compression force in the rubber. These images show the two packers after the test fixture was cut open. Clockwise from top left is the first cut on the HP side; failure channel on packer 1’s HP side; a thin layer of mud covering the inside of the 9 7/8-in. casing; and indication of the failure channel on packer 2’s HP side.

Conclusions

This test proved that the new high-pressure packer concept would be suitable for the challenging conditions at Valhall. Multiple temperature cycles were run to simulate hydraulic fracturing stimulation, and results show the packer will have high differential-pressure capacity. The test results also show that differential pressure above 10,000 psi is possible on the new design.

Parts of the casing were split open to investigate the failure mode of the packers. Although the packers did not fail in the test, the first packer had damage to the swelling elastomer element. A failure channel went through the length of the first packer, but the rubber was held in place by the new backup ring design, and the packer maintained pressure integrity. The second packer was more or less undamaged. This confirms that the design is able to hold high differential pressure even after the element is damaged.

SPE/IADC 130062, “Case History: New Swellable Elastomer Packer Design Improves Operations in 10,000-psi Differential Pressures in the Valhall Field in Norway,” was presented at the SPE/IADC Middle East Drilling Technology Conference & Exhibition, 24-26 October 2011, Muscat, Oman.

By Ted Littlechild, EFC Group

An EFC Group technician indicates an alarm while operating the switch to change display read-outs on a system designed for HPHT operations. These systems are also suitable for lower-rated rigs’ well control systems.

High-pressure, high-temperature (HPHT) wells are defined differently throughout the industry. The UK Energy Institute’s Model Code of Safe Practice in the Petroleum Industry defines HPHT wells as “where undisturbed bottomhole temperature exceeds 300°F (149°C) and where mud weight in excess of 15.4 ppg is needed, or where pressure-control equipment over 10,000 psi is needed.”

The API does not yet specifically rule on HPHT wells and drilling, although changes in API specifications and recommended practices are anticipated.

It is possible to have HP without HT and HT without HP, often classed as “near-HPHT,” where wellhead pressures of 8,000 psi and 9,000 psi may be anticipated. These deserve as much attention as HPHT wells, especially where gas and condensation is expected.

Although much progress has been made in kick detection techniques in recent years, kicks still occur and vary in type, composition and severity. Kick detection is far from an exact science and, like many critical rig operations, can be subject to the vagaries of human decision-making and experience. As techniques for kick detection continue to improve, the global drive to drill deeper and to find hotter, higher-pressured reservoirs will push ahead as well.

If kicks are inevitable, what is therefore needed is a reliable kick control or kick management system, which must include the hardware and the trained personnel to minimize the significant risks.

Technology development timeline

The first ram-type BOP was developed in the early 1920s by James Abercrombie and Harry Cameron. First deployed in 1924, it was used to stop the routine gushing of successful wells.

Many other improvements in kick control/management followed, especially rotary drilling and improving mud technology to maintain control of pressurized reservoirs, as well as the development of hard-faced chokes and drilling manifolds to improve well control after a kick. These improvements helped, but they did not stop the kicks.

The industry’s operations kept moving forward, primarily offshore, with the added complications of placing BOPs subsea, having risers and the often remote locations of the rig. These issues helped to drive continual improvement of kick detection technology – more difficult on a heaving semi/drillship – as well as the development of kick control methods and crew training and experience.

Yet these developments didn’t stop kicks or blowouts. It is crucial that a rig is equipped with adequate systems to manage kicks to prevent them from developing into blowouts and to control them as quickly as possible, with minimal harm to the crew, the rig and the environment.

Two major North Sea blowouts in 1988 led to significant changes in UK legislation, as well as international practices.

All blowouts have different but equally significant consequences, and the September 1988 blowout in the Central Graben of the UK’s North Sea led to the establishment of an official definition of HPHT wells and to the development of HPHT codes and practices.

What we would now call HPHT wells have been drilled for decades. They were previously known as “difficult or hazardous wells,” which are accurate terms. The September 1988 incident resulted in the UK Department of Energy issuing a moratorium that stopped drilling on all wells requiring BOPs and manifolds rated beyond 10,000 psi and 300°F until specific well control equipment upgrades were installed on the rigs.

The main well control upgrades required by the UK Department of Energy in 1988 were the result of recognizing that HPHT wells introduced risks that had not necessarily been formally assessed and for which specific equipment and training were lacking. The UK government took steps to ensure that specific equipment to deal with the circumstances had to be installed and ready for operation. These included:

• High-temperature elastomeric seals in BOPs and wellheads;

• A properly engineered mud-gas separator in place of the poorboy degasser with a derrick vent line terminating at or above the crown and where flow rates, size and capacity were calculated;

• High-pressure overboard “blowdown” lines from the buffer tank, effectively bypassing the mud/gas separator: These 4-in./5-in. lines have the same pressure rating as the buffer (5 ksi or 10 ksi) and ideally run straight overboard to port and starboard;

• A system for monitoring and recording temperatures, particularly in subsea BOPs, as well as pressures and temperatures upstream and downstream of both hydraulic chokes; and

• A hydrate inhibitor system set up for the injection of antifreeze immediately upstream of all chokes.

Further, the content of well control training for HPHT was prescribed. During the next few years, a series of UK Continental Shelf (UKCS) notices were issued addressing topics such as the detailed design of the mud-gas separator and liquid seal.

The second significant UKCS blowout was Piper Alpha in 1988. This disaster had nothing to do with drilling, HPHT or otherwise, but the number of fatalities was significant.

The incident was followed by Lord Cullen’s Enquiry and Report, which made many recommendations that would go on to drive a radical shift in the responsibility framework in the early ’90s. Since then, operators and drilling contractors have been required to develop safety cases using risk analysis and matching equipment to risks.

One result is that operators and drilling contractors have developed their own HPHT operating procedures, and although many of these differ in detail, they are similar in their main conclusions and requirements.

Since the early ’90s, some or all of these equipment upgrades have been fitted to many 15,000 psi-rated rigs worldwide and to some 10,000 psi-rated units. They are not only suitable for HPHT operations but are sensible additions to well control systems for most rigs.

In some parts of the world, there has been little or nothing by way of HPHT operations, but as energy demand grows and the production of reservoirs plateaus and declines, it is inevitable that ever-deeper wells will be planned and drilled in all regions. The early name of “difficult” or “hazardous” wells is accurate, so the issue is how to mitigate the hazards when drilling deeper into these hotter, higher-pressure zones.

The EFC Advanced Choke Control System for dual remote choke control incorporates a well control system to assist decision-making during critical incidents. The choke control generates hydraulic power for control of additional overboard valves.

Upgrades

It should be assumed that the rig selected for an HPHT program is already equipped with, among other things:

• A 15,000-psi stack;

• At least one choke and one kill line with HCR valves;

• 15,000 psi-rated chokes – usually four chokes with a split buffer tank, because well kill operations can take days and weeks to complete. Normally, two chokes are hydraulic and two are manual, although that’s conventional and we occasionally have manifolds with four actuated chokes;

• An updated mud system, with plenty of capacity for solids control, mud mixing and bulk handling; and

• Properly functioning safety systems, e.g., gas detection, deluge systems, life boats, etc.

These assumptions cover the way in which a newbuild rig will often leave a yard: equipped with 15,000-psi equipment but not ready for HPHT operations. To be fully prepared for HPHT operations, the rig requires most if not all of the following additional systems, which are often added to newbuilds after leaving the yard.

Control & monitoring systems

• Liquid seal monitor;

• Finescale pressure gauges – high-resolution manifold, analogue pressure gauges;

• Interlocked overboard valve control system;

• Open/close status indication of manual valves;

• Temperature up/downstream of both remote chokes;

• Glycol injection unit;

• Formation integrity test/leak-off test (FIT/LOT); and

• Possible future requirements, e.g. BOP event logger.

Liquid seal monitoring system

The liquid seal monitoring system reflects how the liquid seal operates on the basis of differential pressure across the seal. An alarm alerts the driller to imminent loss of his liquid seal and the need to take action.

EFC finescale pressure gauges allow drillers to see small pressure changes in the manifolds. The panel incorporates a liquid seal monitor, which uses two sensors to monitor the liquid seal in different pressures.

Finescale pressure gauges

Large analogue gauges, which considerably improve the driller’s ability to see small pressure changes in the manifolds: choke & kill (C&K), standpipe (sometimes S/P 1 and 2) and sometimes cement/kill pump. Interface analogue gauges can be preferred to digital gauges because analogues have more visibility. Full-scale bourdon tube gauges showing drill pipe and casing pressures are an API requirement for choke control systems (API Specification 16C), so the finescale gauges augment them.

Interlocked overboard valve control system

At its simplest, this system controls and sequences two valves: the buffer tank to mud-gas separator line valve and the blowdown valve (the buffer to overboard line valve). These valves, usually 4-in./5-in. to match the lines, are hydraulic and rated to the same pressure as the buffer (5,000 psi or 10,000 psi OP) and are interlocked so that fluids do not become trapped in the buffer tank but can either flow through the mud-gas separator or overboard.

There are usually two overboard lines, so there may well be three or four hydraulic valves to be controlled and interlocked to ensure that well fluids are not trapped. An override switch is needed so that, when not operational, the buffer can be closed off and pressure tested.

Furthermore, the choke control system often generates hydraulic power for control of additional overboard valves. When this is the case, an additional accumulator should be added so that the open/close performance of the chokes is not affected and the API requirement to close the choke within 30 seconds (20 seconds with an accumulator) is maintained.

Open/close status indication of manual valves

The UK Energy Institute publication referred to earlier recommends that sufficient C&K manifold valves be remotely actuated to “avoid the close proximity of personnel to high-pressure lines.” The open/close position of these actuated valves must be directly monitored using proximity switches with their status displayed on a panel.

The manifold also has a quantity of manual valves. They do not usually have a rising stem, and their open/close status is not readily apparent. This means that the fluid flow path through the manifold is not immediately obvious, and mistakes can be made during well control incidents.

The solution is to monitor the status of the manual valves, and this can be done using sensors that monitor valve stem rotation; the signal is fed back to a screen or pairs of LEDs on a panel.

Temperature upstream & downstream of remote chokes

Temperature changes present two potential dangers: high temperatures upstream of the chokes and low temperatures downstream of the chokes.

The danger of high temperatures is that of exceeding the temperature rating of the ram, valve and choke seals and elastomers. If that happens, well flow can no longer be effectively choked back, and the well control capability of the rig becomes dangerously reduced.

The danger of low temperatures downstream of the chokes is that, as the chokes do their job and create a pressure drop, an associated temperature drop occurs, leading to the dangers of the gas component freezing into hydrates, restricting the flow and even blocking the low-pressure manifold pipe work. Again, the result will be that well flow can no longer be effectively controlled, and the well control capability of the rig becomes dangerously reduced.

Monitoring mud temperature

In a manifold, monitoring mud temperature should take place at locations where mud is flowing, not at a dead end such as an instrument block. Wrap-around sensors effectively work. They do not require additional drilling and tapping of the manifold, and they can be located, more or less, at the best positions for temperature monitoring.

A standard EFC glycol injection unit with dual acting pumps has a 40-gal (150-liter) reservoir. The unit helps prevent hydrates from forming downstream of the chokes by injecting glycol as a hydrate inhibitor upstream of the choke.

Glycol injection unit

To prevent hydrates from forming downstream of the chokes and blocking the manifold flow lines, glycol is injected as a hydrate inhibitor, or antifreeze, upstream of each choke.

A dedicated glycol injection unit is needed, with dual pumps that match/exceed manifold pressures so the pumps each need to be able to output more than one liter/min at 15,000 psi. The pumps are usually rated to a maximum of 23,000 psi.

One question often asked is, “How much glycol is needed?” The answer simply is, “Enough to do the job,” which is not very helpful, but well fluid and gas compositions and rates of flow in exploration wells are not usually known in advance, and experience has shown that “the one liter/min at 15,000 psi” rule of thumb works.

FIT/LOT

Formation integrity tests and leak-off tests are traditionally recorded using graph paper and pencil, and decisions are taken onboard.

Systems are available for monitoring the FIT/LOT testing, recording to a PC and transmitting the data to shore-based experts in real time, who can then help with the FIT limit decision-making. One further advantage is that FIT/LOT data are recorded electronically and can be used to help with future drilling operations and well planning.

Looking ahead

Managed pressure drilling (MPD) is a technique being adopted globally, especially in HPHT wells, providing a considerable improvement in well control and reduction the frequency of kicks. MPD allows greater control of bottomhole pressures while drilling, but it is important to realize that when a kick is detected, it is the rig’s BOP, C&K manifold and systems like the ones described in this article that are the used for kick control purposes.

As a result of the 2010 Macondo blowout, API and IADC committees and joint task groups have been working on well control issues and equipment. There are likely to be some far-reaching changes, especially – but not only – aimed at deepwater drilling and HPHT drilling. Full details of these changes are not yet known, but they are likely to focus on BOP configurations, BOP testing, BOP data handling and off-rig transfer, C&K manifolds, mud/gas separator issues, and personnel competence and training.

Greater procedural rigor and attention to detail is required. Through time, as shallow, “easy” oil and gas fields have been discovered, developed and depleted, operators have had to drill deeper into hotter, higher-pressured reservoirs. This global trend is gradually exposing more operators to HPHT conditions, with potential well control issues.

Thorough equipment upgrades and crew preparation are prerequisites to minimize the risks and to maximize safety, environmental protection and operational profitability.

This article is based on a presentation at the 2010 IADC Well Control Middle East Conference & Exhibition, 29-30 November in Manama, Bahrain.

EFC Group, formerly Electro-Flow Controls, provides well control systems for HPHT drilling focusing on enhancing the systems that are typically provided with the BOP, manifolds and accessories.

By Ron Ayllon and Randy Hansen, Schlumberger

Recent developments in drilling automation processes and software systems have enabled dramatic improvements in rate of penetration (ROP). These systems have been used to optimize performance in the Chicontepec field development project onshore Mexico. Rig operations are being controlled from a facility in the nearby city of Poza Rica using a “factory drilling” concept that reduces the number of staff required on the rig and optimizes the benefits of available expertise.

Drilling optimization

Drilling operations represent a significant proportion of the cost of a well, so increasing ROP without detrimentally affecting hole quality or well placement saves time and money. Technological improvements help reduce the time and cost of developing fields and can enhance the production of hydrocarbons to surface, but these improvements can only be fully realized by optimizing the use of available drilling equipment and human expertise. Drilling optimization is the next step in the long-term evolution of the drilling process, leveraging gains made through mechanization and automation.

Drilling mechanization is an enabler for drilling automation, which makes drilling automation an enabler for drilling optimization.

Drilling mechanization developments have focused mainly on assisting limitations of human strength and reducing risk of physical harm on a rig. Elements include increased use of hydraulic, electric and pneumatic power, combined with reduced manual intervention with equipment and more remote operations. The mechanization of previously manual tasks has been successful in improving the safety of operations and has changed the profile and duties of a traditional drilling crew; however, it has had little impact on reducing the need for human intervention in the tasks required on a rig.

Drilling automation aims to reduce the impact of human behavior and risk of human error, with the goal of producing the same optimum result consistently, regardless of who is operating the equipment. The approach is similar to that taken by several other time- and safety-critical industries – such as aviation and petrochemical processing – that have acknowledged human limitations in managing repetitive or complex tasks and have turned to automation. The idea is not to eliminate the driller or drilling crews but rather to provide them with tools to enhance their performance.

The ROP improvement realized with the ROPO drilling optimization algorithm has varied from 4% to 112%. Each circle represents a hole section; the size of the circle is proportional to the length of the section. Greater use of the ROPO algorithm has generally resulted in greater gains in ROP. The algorithm is based on the drilling response of a polycrystalline diamond compact bit.

Automation software

Schlumberger has developed a software tool based on a mathematical algorithm that uses real-time data to determine the combination of rotary speed (RPM) and weight-on-bit (WOB) as a function of the formation being drilled that will deliver the best ROP. The algorithm in the ROPO rate of penetration optimization is based on the modeled drilling response of a polycrystalline diamond compact (PDC) bit. Input data include surface and downhole measurements and parameters of the top drive, drill pipe, mud and bit. The algorithm computes RPM and WOB parameters that will deliver optimum ROP.

However, the parameter recommendations always stay within safe operating limits determined by the operator for the well being drilled.

The ROP optimizer can be configured to continually monitor and automatically control drilling parameters in a closed loop, to effectively “push the buttons” and drill without human intervention. In most applications to date, however, the software has been run in “advise mode,” where suggested changes to drilling parameters are made through human control. In wells drilled with mud motors, the drilling optimization automatic control is only effective when the drill string is turning – not when building angle in sliding mode. When used with rotary steerable systems, the software control is always active.

The algorithm has been tested in more than 200,000 ft of hole in more than 15 drilling operations around the world in both advise and control modes. It has been applied in hole sizes ranging from 6 ¾-in. to 16-in. and at all inclinations from vertical to horizontal. The system has consistently recommended parameter changes that improved ROP compared with either the driller’s performance in the same hole section with comparable lithology or the field average with a comparable bottomhole assembly.

In a well in Algeria, the system improved ROP up to 26% over the offset well average for the section. In Holland, it delivered increases in excess of 30%. Maximum benefit is realized when automation is implemented by means of the closed-loop system, whereby the set points for WOB and RPM are directly fed to the controls of the drilling rig equipment.

Schlumberger uses its RigPulse system to link the automation algorithms with the rig control system. This interface provides access to real-time rig data and enables two-way communication of key controls including WOB, flow rate and RPM. The automation routines have been run both at the well site and remotely. As long as there is sufficient reliable bandwidth, it does not matter where the programs are run. Typically, the operator setting up and overseeing the automation routines is located remotely; however, in all cases, the driller on the drill floor has complete control to engage or disengage from the automation system. The automation is designed around the human operator and not the other way around.

Factory drilling

Automation takes care of immediate repetitive processes at one rig site, but most large development projects have several rigs working in an area with similar environments and the same technical challenges. In high volume, multi-rig campaigns, achieving drilling optimization also requires optimizing the contribution from qualified human resources – leveraging their expertise and experience. The factory drilling concept addresses the frequent challenge of limited availability of reliable and experienced people to supervise operations.

The factory drilling approach is not suitable for all drilling projects, particularly those with a high level of uncertainty and where subsurface conditions are poorly understood. However, many development projects meet the required conditions:

• Multiple drilling rigs;

• High volume of wells per rig;

• Repeatable well design/well program; and

• Predictable downhole conditions with limited downhole risk.

Such environments foster a factory drilling process, enabled by seamless integration of services, multitasking of personnel and the use of fit-for-project rigs. The concept leverages the power of drilling optimization software and optimizes human expertise. It reduces cost and HSE exposure related to having personnel on the rig, so it has particular benefits for operations in remote areas.

Factory drilling requires close partnership between involved parties – including the drilling contractor, project manager and the operator.

A factory drilling cell in Poza Rica, Mexico, controls rig operations in the onshore Chicontepec field development project. The Poza Rica facility houses four cells that monitor real-time data of 12 rigs 24/7. A factory drilling supervisor, a senior well engineer, a directional driller and a well engineer make up one cell, which communicates with a rig manager on location.

Case history

The Schlumberger Integrated Project Management (IPM) group has been working with PEMEX since 2002 on its Chicontepec Project near Poza Rica, Mexico. This project is drilling multiple directional wells, each from multiple drilling pads using skid-mounted, fit-for-purpose rack and pinion and telescopic-double rigs from Saxon, a Schlumberger JV company. Rig count has fluctuated, and during 2009, it more than doubled to 17. Early in 2009, it became clear that the planned rapid increase would put a strain on available expertise, and a pilot plan was formed to move toward a factory drilling operations setup.

The first three factory drilling cells, handling three rigs each, were fully functional by June, and the fourth cell was fully functional by November 2009. The four factory drilling cells, running 24/7, are located next to one another in a Poza Rica office facility and are together handling 12 rigs. Each cell is equipped to monitor real-time data from each rig, control operations on each rig and communicate directly with each rig to discuss ongoing activities with a designated person on location, usually the drilling contractor’s rig manager. Each cell has a factory drilling supervisor, a senior well engineer, directional driller and well engineer.

The system has enabled significant reductions in personnel requirements, including eight well-site supervisors and 12 directional drillers, relative to what would be required to control 12 rigs from people all in the field.

The ROPO drilling optimization algorithm has been applied throughout the operations. Until recently, recommendations from the system were communicated to personnel on each rig for implementation. In May 2011, the first permanent installation of RigPulse running the ROPO service in closed-loop automation mode commenced on Saxon Rig 162. A second rig (Saxon Rig 163) started automated drilling afterward.

Preliminary results have been encouraging, with ROP increases greater than 25% in the 9 ½-in. and 6 ¾-in. hole sections. The ROP optimizer has maximum effect when running in “closed-loop” mode, as adjustments are made instantly and fine-tuned continuously. To date, it has delivered a 40% increase in on-bottom ROP relative to hundreds of previous wells in the area.

Field tests and commercial applications show that automated interpretation of drilling mechanics data can be used to control drilling parameters and improve performance. Automation will not replace drillers but should help them by performing the more mundane and repetitive tasks so that drillers can concentrate on the safety of the rig crew and the safe construction of the wellbore.

ROPO is a mark of Schlumberger.

Activities related to oily and liquids-rich plays in the onshore US have risen significantly since 2008. From 2001 to 2008, fewer than 20% of US land rigs were drilling in these plays. Today, oil and liquids-rich targets, including the Eagle Ford (horizontal gas), Marcellus (West Virginia, southwest Pennsylvania), Granite Wash (horizontal gas) and Cana-Woodford (horizontal gas), represent two-thirds of the market’s total rig count.

Supply/demand likely to keep drilling levels high; US onshore rig count expected to increase by 15%

By Katie Mazerov, contributing editor

Amid macro-economic uncertainty and market volatility, analysts are putting the industry on a promising-to-bullish track for 2012 as oil prices remain solid, rig counts rise and the offshore industry turns the tide from the doldrums it was in a year ago.

Despite a downturn in North American shale gas production, most industry watchers are seeing an uptick in activity as evidenced by significant discoveries in the North Sea and Gulf of Mexico (GOM), the continued ramp-up offshore Brazil, steady growth in the West Africa and Asia Pacific markets, and an active and growing international liquefied natural gas (LNG) trade.

The global supply of oil, considering OPEC spare capacity, remains challenged. John Keller of financial services firm Stephens Inc said he believes drilling activity outlook for 2012 is promising.

After a year marked by post-Macondo jitters, heightened regulations and the Arab Spring, analysts believe the industry is ready for a healthy return to stable growth.

“In investors’ minds, macro fears are trumping everything else at this point, whether it’s slowing economic growth, the potential for recession or fears about European debt,” said John Keller, vice president and oilfield services research analyst for Arkansas-based financial services firm Stephens Inc. “But through all these fears, when you look at oil prices, the global outlook for drilling activity as we go into 2012 remains pretty promising.”

From a supply and demand perspective, international supply remains challenged, he said. “The fallout from the split among the OPEC countries earlier this year, with Saudi Arabia moving forward with development plans in light of desired production cuts by other OPEC members, hasn’t fully started to ramp, yet. That will underpin growth in that region, as will continued development in Iraq.”

From left, John Keller, Marshall Adkins and Collin Gerry

There is some uncertainty about the impact on supply and oil prices by the anticipated return to production in North Africa following the Arab Spring. “The wild card is how quickly Libya will recover,” said Marshall Adkins, managing director of energy research at Raymond James & Associates.

“But even when we factor Libya coming back online mid-2012 and a global recession, which implies the OECD (Organization for Economic Cooperation and Development) will be in recession, the global oil model is just about as bullish as I’ve seen in decades.”

The global jackup market is poised for a rebound, with Asia and the Middle East leading the way, according to Collin Gerry of Raymond James & Associates. Global jackup utilization has increased to 90% (top), and the number of jackup rig years contracted per quarter has accelerated above pre-recession levels (bottom).

Barring a severe recession emanating from Europe, supply and inventories are low enough to keep oil prices firm, he added. Oil prices also will hold up if governments opt to print more money in response to over-leveraged situations.

“Fundamentally, from a supply/demand standpoint and from a global money situation, oil will continue to be the main driver of activity, particularly in North America, where drilling is expected to see double-digit growth, mostly in the liquids-rich and oil plays,” Mr Adkins said.

Due to typically slower growth rates, the international market will see growth of 6% to 9%, he continued. Higher natural gas prices in most international markets will support continued production in shale and other unconventional gas plays, particularly in Australia and South America.

The global jackup market is poised for a rebound, as utilization has increased from 82% to 90%, signaling an increase in rig pricing, Collin Gerry, vice president, Oilfield Equity Research at Raymond James. “Almost all jackup activity is driven by Brent oil prices, which have remained above $100/bbl,” Mr Gerry said.

Asia and the Middle East lead the jackup market. “Currently, there are 100 jackups in Asia, including India, China and Southeast Asia, which is at the high end of the historic demand range,” he noted.

“The nuclear disaster in Japan and moves by Germany to shut down reactors also will bolster the outlook for LNG,” Mr Keller said. “Oil prices are the driver for international activity simply because LNG internationally tends to be priced off oil prices or some function of oil prices.”

Gulf of Mexico

Oil will continue to be the focus of activity in the GOM, but ongoing and heightened regulations and the still-slow pace by the US government to issue permits cloud the post-Macondo picture.

“The GOM remains a political football on outlook, but it will really boil down to how quickly permits continue to be issued, and sustainability of the level of permitting will determine how that market plays out,” Mr Keller said. “When you’re a major operator looking out across the globe, where access to hydrocarbons is becoming more restricted due to geopolitical events and nationalization, the GOM still looks very good and the resource potential is there.”

A positive development has been the recent large ultra-deepwater discoveries by ExxonMobil, Chevron and BHP Billiton in the highly pressurized Lower Tertiary geological formation.

Dane Groeneveld

“Even before 2010, we saw companies reducing their exploration and appraisal drilling campaign budgets,” said Dane Groeneveld, regional director for NES Global, which provides engineering services and specialist staff support for the energy industry worldwide. “The situation was already difficult; then Macondo happened.

“But we are seeing a return to more work in the Gulf, with operators allocating more time and resources in the geoscience departments for future developments,” he continued. “As a result, we are seeing an increase in rig rates and support for more drilling going into 2012.” NES Global is being asked to find development geologists, reservoir engineers and drilling engineers for work on developing assets in these leases. “The uptick this year will be a continuing trend over the next few years,” Mr Groeneveld said.

Philip Weiss

Permitting remains an issue, however. The active deepwater rig count in the Gulf had moved up to more than 20 by early October, higher than it was last year but still well below pre-Macondo levels. “We’re seeing a lot of interesting prospects with significant potential, but because of the government’s slow pace in issuing deepwater permits, we haven’t been able to move these discoveries and previous discoveries forward, which is disappointing,” said Philip Weiss, senior analyst, energy for Argus Research.

“Operators are sitting on a lot of nonproductive capital because they can’t get these projects moving,” he continued. “We have 23 (active deepwater) rigs in the Gulf now, but there are questions about what will happen when that work is completed. There is not a pipeline of other projects with permits in place. That increases the risk that rigs could once again be realizing reduced dayrates while waiting for work. Both operators and rig owners suffer under those circumstances.”

Meanwhile, new regulations mandating such activities as unannounced spill drills and stronger disclosure requirements have been implemented. On 1 October, the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) split into two agencies. The Bureau of Safety and Environmental Enforcement (BSEE) will be responsible for inspections, enforcement and safety of offshore oil and gas operations. The Bureau of Ocean Energy Management (BOEM) will oversee energy leasing and planning on the Outer Continental Shelf (OCS), along with offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans.

Shale – shift to oil continues

The disparity of oil prices holding steady at $80 or above and low natural gas prices continues to drive the shift by North American operators from dry gas plays to reservoirs characterized by a mix of hydrocarbon gas and natural gas and liquids and/or oil. The expected drop in the gas rig count will be offset by the increase in the oil rig count, with the overall US rig count expected to increase by approximately 15% next year, then 10% to 12% annually for the next few years, Mr Adkins noted. “Canada will mirror that trend,” he added.

Ironically, the technologies developed for dry gas plays are driving the growth in liquids plays such as the Bakken and Eagle Ford, both showing a marked increase in rig counts. “In a very rational way, the industry is chasing oil prospects with the technology it developed for the Barnett, Haynesville and Woodford plays that are now seeing a downturn,” Mr Keller said. “Five years ago, roughly 80% of the rig count in the US was deployed in natural gas plays. Now, it’s much more of an even split.”

Also significant is the horizontal component of the oil rig count. “Today, more than half of the oil rig count is drilling horizontally, compared to 25% to 30% at the beginning of 2008,” he noted.

Data from Smith Bits STATS show the Eagle Ford rig count at 213 in early October, up from 134 at the end of 2010, and the Bakken count up to 191 from 157, Mr Keller noted. The same is true in the Permian Basin, where Smith Bits puts the rig count at 330, from 258 at the end of last year. “The Permian Basin has been a significant growth area for the US in 2011,” he noted. “While the play is generally considered conventional, it has some unconventional formations, and operators are using a lot of horizontal drilling and hydraulic fracturing technology to access multiple zones in one wellbore.”

John Spears

Overall, activity in the Eagle Ford, Bakken and Permian Basin will see a 20%-plus growth in 2012, said John Spears, president of Spears & Associates, who agrees that the adoption of shale gas technology has been significant. “Nearly 100% of the drilling in the Bakken and Eagle Ford plays is horizontal,” he said.

Mr Spears projects there will be 2,100 active land drilling rigs in the US in 2012, up from about 1,880 active rigs this year, with utilization around 70%, up from 64%. “The count will include 200 new rigs, most of them high-spec, advanced technology rigs for horizontal and deviated drilling,” he said. He predicts gas drilling will fall 2% to 3% next year as operators continue to migrate from dry gas to other markets.

“US operators also are seeing well costs rise 15% to 20% per year, and dayrates are up about 20% over a year ago, due in part to the growth in advanced-technology rigs,” Mr Spears noted. “The biggest increase in well costs will come from hydraulic fracturing operations, which are up 40% due to tight availability and lead times for crews, and to some degree, environmental issues.”

In Canada, the rig count will increase 8% to 10%, with the total active rig count around 460 in oily plays, he continued. Alberta, which includes the Cardium and Duvernay plays, will continue to account for two-thirds of that, followed by Saskatchewan, which includes a portion of the Bakken formation, then British Columbia.

Beyond North America

The North American shale boom has spread to several international markets, including Southeast Asia, Latin America and Europe, thanks to more favorable international natural gas prices and the export of technology. “The US has been the incubator for the world, and now we’re starting to see emerging markets link up with Western companies,” Mr Spears said. “Because of the active LNG market and international pipelines, international gas prices are up to three times higher than they are in North America. “

In Asia Pacific, Australia, with extensive shale reserves in the Canning Basin, has emerged as the most aggressive player in the shale sector, said Usman Ahmed, vice president and chief reservoir engineer, Reservoir Development Services for Baker Hughes. The country is engaged in an ambitious program to develop shale natural gas resources for export into Southeast Asian markets. Australia’s risked gas in place (GIP) is estimated at 1,381 TCF.

China and India, with risked GIP estimated at 5,000 TCF and 500 TCF respectively, hold extensive shale gas reserves; however, it is anticipated that India will develop faster than China, Mr Ahmed said. “The Indian government has sent out requests for proposal and expects to be drilling the first shale gas wells by mid-2012,” he said. The primary shale basins are located in the country’s northwest and southern regions. Baker Hughes also is working with the Indonesian government on some pilot wells.

“Shale development in China is hindered by two main problems,” Mr Ahmed noted. “The country’s highly populated areas make production more logistically challenging. Even greater difficulties are encountered because most of the shale basins in China are located in areas where there is a significant lack of water, for example, in the Tarim Basin.”

The latest region to enter the shale market is Latin America, most notably Argentina, where the risked GIP is estimated to be 2,732 TCF, and Mexico, where the risked GIP is estimated to be 2,362 TCF. Activity is also anticipated in Brazil, Chile and Bolivia. Halliburton executed the first horizontal, multi-stage hydraulic fracture shale gas completion in Argentina’s Neuquén Basin for Apache Energy in August this year.

All regions are expected to outpace Europe, where extensive shale reserves exist, but production is much slower due to more stringent regulations, Mr Ahmed noted. Poland, where the Baker Hughes rig count was nine at the end of September, is currently the major European shale producer. Risked GIP in the country is estimated at 792 TCF. “Discussions to develop shale in Poland began about three years ago, and the country is now the most active on the continent, primarily because of the government’s energy-friendly policies and willingness to eliminate red tape,” he said.

Cuadrilla Resources, an independent oil and gas company in the UK, recently announced the discovery of a 200-TCF shale gas formation in the Bowland play in northwest England. The company reportedly will submit a development plan to the government in 2012 and hopes to begin production in 2013.

But the big challenge for international shale development is equipment, Mr Ahmed continued. “Regardless of how promising the shale reservoirs are in these regions, there is a severe shortage of equipment from the service sector,” he said. “Manufacturing can’t keep pace with demand. The delivery timetable for frac trucks in North America is six to nine months but can be up to 17 months in other markets.” Lack of personnel remains an ongoing issue as well, but the equipment lag time is giving markets more time to ramp up the work force, he said.

North Sea

Exploration and potential recovery opportunities remain strong in the Norwegian sector of the North Sea. Estimates of recoverable assets for the Avaldsnes/Aldous oil and gas field, discovered on Norwegian Continental Shelf last year, have increased to 1.2 billion to 2.6 billion bbls, making it potentially the third-largest North Sea find and the largest since the mid-1980s. “We are now realizing the prospects for this field are huge,” said Andrew Vinall, technical director for UK firm Hannon Westwood. The field is situated in 115-meter water depths, with reservoir depth at less than 2,000 meters.

The discovery is boosting the overall outlook for the region, despite a reduction in drilling activity in the UK sector. “We feel the number of wells is going to hold up, especially in Norway,” Mr Vinall said. “There are more rigs under construction planned for in Norway than any other North Sea sector.” The active rig count in Norway as of early October was 32; no rigs are stacked, he said. “Utilization in northwest Europe is around 94% for jackups and 90% for semis.”

Several factors, including the surprise 12% tax increase implemented by the British government, have resulted in a major decline in exploration and appraisal (E&A) drilling in the UK sector, where the active rig count is similar to Norway, but with five rigs stacked, Mr Vinall said. Eleven rigs are on E&A wells.

While utilization has remained steady in the UK, more wells are being switched to development drilling. “Also, the UK Department of Energy and Climate Change has been slow to authorize wells this year, and several companies that had very active drilling programs in previous years have been acquired, and the new owners are not as active,” Mr Vinall said.

The region’s increasingly complicated geology, with deeper, high-pressure, high-temperature (HPHT) characteristics, means wells are taking longer to drill than in previous years, he indicated.

Malcolm Webb

Operators are optimistic the UK tax situation can be relieved through incentives, according to Malcolm Webb, chief executive of Oil & Gas UK, an industry group representing the UK offshore oil and gas industry.

“Activity is relatively flat, and the exploration well count this year is particularly low,” Mr Webb said. “We haven’t seen a great exodus, but we are seeing a lot of dismay. The big projects with robust economics are still going ahead, but other, smaller projects are stranded, and we need to overcome that problem or we could see capital being attracted to other parts of the world in preference to the UK North Sea basin.” The basin still holds an estimated 24 billion bbls of oil and gas reserves.

The tax increase has impacted some of the smaller, more technically challenging plays, such as HPHT fields and marginally productive mature reservoirs, Mr Webb noted. “A number of gas projects have been impacted because the price of gas is roughly half the price of oil here.”

The UK government in March raised the corporate tax rate on UK oil and gas from 50% to 62%, and raised the marginal rate on the oldest fields (those that began producing before 1993) up to 81%.

“The government decided that in view of the current economic climate, it should scrap the ‘green tax’ that was designed to reduce demand by making fuel more expensive at the pump,” Mr Webb said. To replace that revenue, the government then imposed higher taxes on producers.

The industry is working with the government to come up with fiscal incentives that would spark incremental production and allow projects to move forward. “If we can come to some resolution on that and gain some bankable assurance from the government that it will pay its share of decommissioning costs, that will be a very positive move for the basin and will help us improve the attractiveness for investment,” Mr Webb said.

On the UK regulatory front, the Oil Spill Prevention and Response Advisory Group (OSPRAG) submitted its final report in September, with most of the recommendations already being implemented, including introduction of a device (see p14) that can cap a free-flowing well in a matter of days, Mr Webb said.

Of concern are moves by the European Commission to take centralized regulatory control over offshore oil and gas E&P operations in Europe. “We are in discussions about that now. We believe control should be left to national regulators who are already doing a very competent job,” he said.

Asia Pacific

Natural gas is the driver for growth in the Asia Pacific region, with Australia engaged in seven LNG projects targeted for Southeast Asian markets. The country’s aggressive coal seam gas (CSG) industry is fueling the growth on the East Coast, paralleling the North American shale gas boom, NES Global’s Mr Groeneveld observed.

“The big spike in hiring activity a few years ago has continued, and we are expecting another big spike at the back end of 2012. The activity is attracting drilling and oilfield service firms from as far afield as Canada, with the major service companies also ramping up their presence,” he said.

Drilling on Australia’s Northwest Shelf and the Timor Sea has also increased, along with developmental drilling in Papua New Guinea to support recent onshore and offshore exploration activity, Mr Groeneveld said. Offshore activity for gas drilling also is gearing up in Malaysia and Thailand. NES Global has offices in Singapore, Malaysia, Vietnam, Thailand and Indonesia, where there has been marked growth on the drilling side of the business. China remains an expanding market for onshore and offshore gas production, he said.

Africa

Operators and contractors in North Africa are anticipating a return to business as the region rebounds from the Arab Spring uprisings, which effectively shut down drilling in Libya. Companies also are exploring entry into Tunisia, where 20 rigs are operating, and continue to show interest in Algeria, a major supplier of natural gas for Europe.

Exploration activity in West Africa, with a number of deepwater fields in Equatorial Guinea, Nigeria, Mozambique, Angola and Ghana, has seen steady growth in the past year, thanks in part to the redeployment of idle rigs to the region from the GOM. “The deepwater potential makes West Africa one of the exciting new frontiers, mirroring Brazil,” Argus Research’s Mr Weiss said.

One of the most prolific is the Jubilee field offshore Ghana at a water depth of 1,250 meters. The field is estimated to hold recoverable reserves of more than 600 million bbls and an upside potential of 1.8 billion bbls.

With 35 active jackups in West Africa, utilization is somewhat challenged by geopolitical issues in some countries, Mr Gerry of Raymond James noted.

However, Mr Groeneveld said West Africa has been a big growth area for NES Global. “We’re seeing 40% year-on-year growth both from the major operators as well as smaller companies. We are placing a lot of professionals into exploration and development phases and for actual project execution for various facilities. We’re also seeing companies sending more environmental professionals and seismic crews to the region for early exploratory drilling and due diligence.”

By Kristin Falk, Borre Fossli, Cathrine Lagerberg, Ocean Riser Systems; Arne Handal, Sigbjørn Sangesland, Norwegian University of Science & Technology

The low riser return system (LRRS) is a method for managing wellbore pressures during offshore drilling operations. It works by adjusting the mud level in the marine riser by returning mud and cuttings to surface through a subsea pump in a separate conduit. It is a single mud gradient, open managed pressure drilling (MPD) system designed for subsea drilling.

The LRRS can be used in two application modes. The first has a full riser during static conditions using conventional mud weights and the capability to lower the fluid level to compensate for the equivalent circulating density (ECD) effect during circulation and drilling as needed. With this technique, conventional well control procedures are used. The second technique involves using higher-than-conventional mud weights and lower fluid levels for both static and dynamic (circulating) operations. Modified well control procedures must be used with this technique.

Both methods improve safety margins, allow for better pressure control and increase efficiency for most well operations.

This article focuses on the well control issues of drilling with a partially evacuated marine drilling riser. Two case examples using data from deepwater US Gulf of Mexico (GOM) wells illustrate how the LRRS gradient fits inside the drilling window.

Figure 1: A “light” version of the low riser return system (LRRS) is connected to a conventional low-pressure marine drilling riser. A subsea return pump module, controlled by a variable speed drive on the rig, is connected to a riser joint via a suction hose. LRRS Light can be used for ECD compensation and improved kick/loss detection.

Low riser return system

By using the LRRS to manage the height of mud in the riser at any one time (level adjustment), the annular and bottomhole pressures (BHPs) can be proactively managed. The system can be used for purely ECD compensation purposes (conventional mud weight) or in combination with a heavier-than-conventional mud weight and lower static level in the riser.

The benefit of using a conventional mud weight is that conventional well control procedures can be used. In static conditions, the riser is full to the flowline outlet or just below. As circulation commences, the rig pumps will be ramped up slowly. The circulation up the annulus will increase the BHP, and the ECD component builds up. The level will then be lowered using the subsea pump, and the control system will continuously adjust the level of mud in the riser to compensate for the increasing BHP due to the ECD effect.

Controlling rates of the rig pumps and the subsea lift pump will keep the BHP or any fixed point in the wellbore near constant and within the desired pore and fracture pressure window. This method can be used to drill the longer hole sections in wells with narrow operational mud windows, such as in depleted formations, and to avoid losses during drilling, cementing and completion.

The full effect of the LRRS technology will be achieved only by increasing the mud weight and using a lower-than-conventional static riser level. In most cases, this allows for managing higher and lower wellbore pressure requirements (both planned and unplanned) by adjusting the fluid level. This gives a higher degree of operational maneuverability to operate in a better balance between pore pressure and fracture pressure and can be applied to all subsea drilling operations after the marine drilling riser has been installed. Normally, the relative effects of the LRRS will be inversely proportional to well depth from the rotary kelly bushing (RKB).

Thus, the potential benefits and effects of using higher-than-conventional mud weights are more significant in the upper part of the well. This makes the LRRS particularly beneficial for deepwater drilling for reasons related to well control and well integrity:

1. Improved safety margins while drilling (larger margin toward kick or loss);

2. Improved kick and loss detection;

3. Improved kick margins;

4. More likely to achieve a riser margin;

5. Possible to circulate out a kick without closing a BOP element;

6. Partially or completely self-regulating with respect to inflow and kicks;

7. Improved cementing operations, which improves zonal isolation; and

8. Barrier and well integrity improvements.

Drilling with heavier mud weights and a partially evacuated marine drilling riser requires new well control procedures and equipment to manage hydrocarbon influxes.

LRRS applications

LRRS is designed to control and manage well pressures. The system has two parameters that can be changed to obtain the desired pressure in the wellbore, namely the mud density (gradient) and the annulus/riser mud level.

Its main applications are related to wells with challenging pressure regimes, such as:

• High pressure combined with a narrow drilling window in deep and medium-deep water. For such cases, a heavier mud combined with a low mud level will give a better fit to the drilling window. The benefit is also useful for shallow water if there are shallow hazards, such as shallow gas, shallow-water flow or mud volcanoes;

• High ECD combined with narrow drilling window. In sections with narrow margins, lowering the mud level can compensate for the increased ECD. This is the case both during drilling and cementing. Surge and swab related to tripping can also be accounted for. One example is highly depleted reservoirs;

• Low formation pressures. Reducing the total static head by lowering the level can allow the use of a better drilling mud that might be too heavy for conventional drilling; and

• Uncertain formation pressure and strength or drilling salt sections.

The system

Two versions of the LRRS have been designated: LRRS Light and LRRS Heavy. LRRS Light is used for ECD compensation and improved kick loss detection; it uses conventional well control procedures and requires minimal incremental rig integration. LRRS Heavy uses a heavier-than-conventional mud, which would, in most cases, fracture the formation if the mud level were brought to surface. This system is dependent on LRRS well control procedures, including implementation of a subsea drilling choke with some additional equipment and well control training.

Figure 1 illustrates LRRS connected to a conventional low-pressure marine drilling riser. An important element of the LRRS is the subsea return pump module connected to a modified riser joint via a suction hose. The LRRS control system operates the subsea return pump controlled by a variable speed drive on the rig.

Pumps can be controlled automatically or manually to obtain the required mud level in the riser. A nitrogen-purging system ensures there are no explosive gas mixtures in the partially evacuated riser. A wiper element is installed above the diverter element, and the evacuated riser is close to atmospheric pressure.

The pump module is launched by a launch and retrieval system over the side of the rig or through the secondary moonpool on dual-activity rigs. An option for running the pumps on the riser also exists. The modified riser joints are installed like normal riser joints. The pump suction hose can be connected to the riser outlet using a ROV.

Barriers

For LRRS Light, the basic barrier philosophy is similar to that of conventional drilling. The primary barrier is the drilling fluid, and the secondary barrier is the subsea BOP. With LRRS, the pressure sensors that monitor the riser fluid level will be part of the primary barrier in that they are needed to verify the integrity (density and height) of the drilling fluid and for volume control. Figure 2 shows the well barrier envelope for the primary and secondary barriers of a typical subsea well.

Figure 2: In typical subsea wells, the primary barrier (in blue) is drilling fluid, and the secondary barrier (in red) is the subsea BOP. The barrier philosophy for LRRS is similar to that of conventional drilling. In LRRS Light, however, pressure sensors are incorporated into the primary barrier to monitor the riser fluid level.

Often in conventional drilling, there is a series of common barrier elements in the primary and the secondary envelope. A failure of any of these shared elements will leave the well without any barrier. For LRRS Heavy, there are generally fewer common barrier elements. For example, the primary barrier is not dependent on the structural integrity of the last casing, the cement, the wellhead or the BOP body as long as the formation has sufficient strength with relation to the primary mud pressure and if the internal well pressure at seabed is lower than or equal to the seawater pressure.

In moderate water depths less than 4,500 ft, the LRRS may alleviate the shortcomings of conventional well control since it would not depend on the integrity of structural elements to maintain the primary barrier. This is because, with the LRRS, the mud pressure will not fracture the formation behind the last casing and there will be less pressure inside the riser at mudline than seawater pressure outside the riser. Hence, a structural failure of the casing, wellhead, BOP or riser will not constitute a well control event as the BHP would increase with the LRRS.

In deepwater, typically below 5,000 ft, the LRRS may be dependent on the same common barrier elements as in conventional drilling.

Primary barrier elements are:

• Drilling fluid;

• Riser pressure sensors (level control);

• Drilling riser;

• BOP body (common);

• HP wellhead (common);

• Casing (common);

• Casing seal assembly (common); and

• Cement behind casing (common).

Secondary barrier elements are:

• Casing and cement;

• Casing seal assembly;

• HP wellhead;

• Subsea BOP body;

• Subsea BOP element;

• Choke line and choke line valves; and

• Kill line and kill line valves.

Table 1: Two wells with different water and total drilling depths were selected to illustrate potential uses of the LRRS. Case 1 represents a typical Gulf of Mexico deepwater well, and Case 2 is based on data from BP’s Macondo investigation, which may not be the exact numbers encountered in the well.

Case examples

Two wells have been chosen to illustrate the potential use of the LRRS. Case 1 represents a typical GOM example, and Case 2 is based on publicly available Macondo data (Table 1). The casing program, pressure window and mud data for Case 2 are taken from the investigation reports and may not be the exact numbers encountered in the well. The two cases represent challenging wells but with different water and total drilling depths to show the relative effects on system applicability.

Drilling mud window

The drilling mud window defines the operational area for mud weights. If the pressure gradient in the open-hole section drops below the formation pore pressure gradient, there is a risk of inflow into the well. Conversely, if the pressure gradient in the open-hole section exceeds the formation strength, losses may occur.

For conventional drilling, the mud gradient will be a vertical line starting at flowline level at atmospheric pressure conditions. The seawater gradient will be lower than most drilling fluid densities. The combination of deepwater and the rapid increase in pore/fracture pressures below the mudline result in a conventional mud gradient not fitting well into the mud window.

Since the mud gradients normally are plotted in relation to the drill floor level (RKB), the LRRS mud gradient approaches zero at the mud/gas interface in the riser and approaches a straight vertical line in very deep well intervals. Hence, the LRRS gradient is now a curve, which shifts to the left of the conventional line. The two case examples will show how the LRRS shifts the mud gradient profile so that it has a better fit within the operational window.

Figure 3: In the drilling window for Case 1, the LRRS gradient does not approach the pore and fracture limits, which reduces the risk of an influx/loss situation.

Drilling window – Case 1

Figure 3 shows the drilling window for Case 1. The planned conventional mud gradients are represented by black vertical lines (only the gradients in the open-hole sections are shown). The graph also shows that eight casing/liners and eight different mud weights were planned for the well. The conventional mud gradients almost cross the pore and fracture gradients, and the risk of taking an influx or a loss is significant.

The green line represents the LRRS mud gradient with only one mud weight. The LRRS gradient is close to zero (air gradient at atmospheric pressure) in the riser above the mud level. Since the gradient calculation assumes a completely filled riser, the LRRS gradient appears to increase with depth even though only one density is used.

In this well, the LRRS gradient fits into the drilling window from the first casing depth (surface casing) to total well depth. It would be possible to drill the entire well using a mud level in the riser of 1,600 ft below RKB and a mud weight of 17.2 ppg.

The LRRS gradient line does not approach the pore and fracture limits. This significantly reduces the risk with the LRRS of getting into an influx or loss situation compared with conventional drilling approach (represented by the vertical black lines).

With LRRS, the primary barrier in this well is always in place. Further, casing points can be selected based on criteria other than the gradient envelope. The well can be drilled with higher kick margins even if the casing program were reduced from seven casing strings below surface casing (conventional) to four casing strings. Use of LRRS would reduce both drilling time and cost and improve safety margins.

Figure 4: In the mud gradient window for Case 2, the LRRS mud gradients fit better within the window than gradients for conventional drilling.

Drilling window – Case 2

Figure 4 shows the mud gradient window for Case 2. The mud gradients for conventional drilling are represented by vertical lines (black), and the green sloping lines represent the LRRS gradient.

The graph shows that LRRS mud gradients fit better within the operating window. As a result, the probability of loss by exceeding the fracture pressure is significantly reduced, allowing for safer and more efficient drilling. In the real operations of the well, there were substantial problems experienced with loss and gains through several hole sections, likely due to narrow pore and fracture pressure margins.

Figure 5: In the 16-in. section of the well in Case 2, the LRRS mud gradient is at a lower risk for a kick or fracture since it fits better within the drilling window, allowing for greater margins of safety.

Kick margin Case 2

Kick margin is typically defined as the maximum volume of gas that can be circulated out of the well without fracturing the weakest formation in open hole. The actual pressure is an input parameter to kick-margin calculations.

Figure 5 zooms in on the 16-in. section for the Case 2 well, illustrating that LRRS will have reduced kick and fracture probability. The LRRS mud gradient is sloping and fits the deepwater drilling window better, which allows for greater margins toward both pore-pressure gradient and fracture-pressure gradient.

Riser margins

A riser margin is present if the mud weight used is sufficiently high to balance or exceeds the pore pressure if the drilling riser is disconnected from the BOP.

In nearly all conventional deepwater operations, the pressure at the disconnect point inside is higher than the external seawater pressure, resulting in no riser margin. If a riser margin is not present, a riser disconnect leaves the well with only the secondary barrier.

LRRS Heavy allows the use of heavier muds, making it possible to obtain a riser margin in many deepwater wells.

Riser margin Case 2

The Case 2 well was drilled conventionally without a riser margin. Using the LRRS, it is possible to achieve riser margins in all but the last section if the conventional casing program is used as a basis. Note that there was a pore pressure regression in the reservoir section (Figure 4). With a slightly modified casing program, setting the 9 ⁵/8-in. casing below the high pressure peak at approximately 17,700 ft, a riser margin would be achievable.

Cementing

Getting a good cement job is a challenge, especially in narrow drilling windows. Conventionally, this challenge can be solved by reducing the circulation rate and using a low-density cement. Unfortunately, this can result in inadequate cement jobs and poor zonal isolation. Using the LRRS, it is possible to achieve improved cementing by compensating for density and ECD effects.

Cementing in narrow drilling windows

The limited pore/fracture window often limits the density of the cements that can be used and may lower the compressive strength of the hardened cement. This usually requires the use of lightweight lead cement (filler) and a smaller amount of conventional (tail) cement. The volume of tail cement may be just enough to cover the zone(s) of interest, plus some excess. Fluid losses, channeling or an underestimation of the excess volume required could leave the desired zone inadequately covered and without a barrier to prevent flow.

The lead cement, if left across a reservoir or pressured section, may not have enough compressive strength to provide a long-term pressure seal. The cement may not be strong enough to avoid cracking when the casing is pressured (and expands). In all cases, an effective barrier to the annular flow of fluids/pressure may not be present over the life of the well.

It should be noted that use of lightweight lead cement is a common and effective option and is not only used when a narrow pore/fracture gradient window is encountered.

The limited pore/fracture pressure may also limit circulation rates while pumping the flushes, spacers, cements and displacement fluids during the cement job. This reduces the overall displacement efficiency, potentially leaving pockets of gelled mud, mud filter cake and cuttings beds. This can result in a flow channel in the annulus.

If the cement has insufficient strength when the casing is pressured, a micro-annulus around the casing can be formed. This can happen even if the cement fully fills the annulus. Again, this reduces the cement’s effectiveness as a barrier.

Another issue to consider is timing for setting of the casing seal assembly or liner hanger seal in deepwater and deep wells. The hydrostatic head of the mud/liquid above the seal is lost. Only a small leak of fluids to the formation above the cement may initiate a cross-flow between formations, before the cement is cured.

Because this effect received little attention before Macondo, little work has been done to shed light on this effect. The LRRS may reduce the risk of gas migration during the cement-curing period. At any rate, operators should evaluate their procedures as to when the casing/liner seals are set after a cement job.

Cementing – Case 2

Figure 6: In the narrow pore/fracture window of an 8 ½-in. section during cementing operations, LRRS can facilitate a better cement job by lowering the fluid level in the riser to compensate for the ECD effects.

The example illustrated in Figure 6 shows a narrow pore/fracture window in an 8 ½-in. section during cementing operations. The orange line shows the annular pressure profile of 14.2 ppg mud to 17,160 ft and 16.7 ppg cement below to 18,300 ft.

With conventional circulation, the ECD effect shifts the hydrostatic pressure profile to the right (dotted black line) where it exceeds the fracture pressure, which can lead to formation fracturing, lost returns and, ultimately, an unacceptable cement job.

However, with LRRS (Light or Heavy), the fluid level in the riser can be dropped to compensate for the ECD effects (dotted green line) to reduce or eliminate the risk of fracturing the formation to obtain a better cement job and zonal isolation. If the only available circulation technique is conventional, one would be required to reduce the densities of various volumes of the cement/spacer slurries to compensate for the ECD effects.

Influx and loss detection

Influx and loss detection is improved in LRRS compared with conventional drilling. If an influx occurs during steady-state operations, more volume needs to be pumped out of the hole than what goes in. As a consequence, the pump speed and power will increase, which will be picked up by the control system linked to the level in the riser.

Note that the level in the riser is not affected by rig movement like the conventional mud line on a floater.

It may no longer be required to put the well on observation for flow checks or wait for a sufficiently large pit gain to accurately detect an influx. Pit gain would be the ultimate result, but with more accurate flow measurements, well control procedures may be initiated earlier.

When a potential influx is detected, the procedure is to immediately turn down or stop the LRRS return pump. This will increase the riser level and BHP.

Circulating out an influx with LRRS Heavy

With LRRS Light, the influx can be safely circulated out using conventional well control procedures, but LRRS Heavy requires special well control procedures. LRRS well control procedures are based on the driller’s method of circulating out with constant drill pipe pressure adjusting a subsea choke. Detailed procedures have been presented at the IADC Well Control Asia Pacific 2009 Conference and the 2010 IADC Well Control Europe Conference.

In the scope of this article, the principle differences between conventional circulation procedures and the LRRS Heavy procedures are explained:

1. Drilling with LRRS Heavy means that the mud weight is higher than the maximum achievable kill mud weight conventionally.

2. The well may not be shut in with the drill pipe full of drilling fluid as conventional. Either of the two alternatives below would prevent the formation from “seeing” the hydrostatic pressure of the drilling fluid from surface:

a. Install a drill pipe differential pressure valve.

b. Initialize the LRRS circulation procedures and U-tube the drill string prior to closing the well.

3. The choke line incorporates a subsea choke valve and a low-pressure bypass from the choke line into the main bore of the riser a distance above the outlet to the LRRS pump.

4. The well can be brought to overbalance dynamically by increasing the mud level in the riser; hence, there is typically no need to weight up the mud.

5. The BOP is normally closed during a kick circulation, but there may not be a hurry to shut in the well by closing a BOP element.

6. The kick is circulated out of the well using the constant drill pipe pressure (CDPP) principle, where CDPP is kept constant by regulating the pressure on the subsea choke valve. Alternatively, a minor influx can also be circulated without shutting in the well (closing a BOP element) and regulating the liquid height.

Figure 7: The LRRS control system will keep the mud level in the riser constant until an influx or loss is detected. Under LRRS well control procedures, if an influx is detected, the return pump is set to idle and the fill pump starts, increasing the mud level in the riser. In this simulated case, when a kick was detected, the subsea pump was set to idle, causing the mud level and the BHP to increase.

Influx simulation – Case 2b

This section describes how LRRS can react to an influx. The simulations are based on a transient two-phase flow model specifically adapted for the system. The flow simulator is a one-dimensional, drift-flux model, where a mixture impulse equation and a mixture energy equation are solved simultaneously with the pressure equation and a slip relation. Two separate mass balance equations are also solved with updated velocities.

In the simulations, any changes of LRRS or fill pump flow rates occur suddenly. The level controller is set to a constant level, and any flow of gas into the well is immediately compensated for by the LRRS subsea pump pumping out the same amount until inflow is detected and a control procedure has been initiated.

Dry gas and a compressible water-based mud of density 15.4 ppg at surface conditions were simulated. The mud level in the riser is initially 1,805 ft below the rig floor. The well consists of a 21-in. marine riser combined with BOP and a 9 ⁷/8-in. casing. The casing shoe is at 17,168-ft TVD with a 8 ½-in. open hole below. The well is assumed vertical with a uniform 5-in. drill string. The flow rates from the rig pumps are 317 gal/min throughout the simulations.

The control system keeps the mud level in the riser constant until an influx or loss is detected. As soon as an influx is detected, the return pump is set to idle and the fill pump started, resulting in a mud-level increase in the riser. This is part of the LRRS well control procedures and will be followed by closing in the well at the subsea BOP (not simulated here).

To illustrate kick detection, a simulated case with BHP below the pore pressure is used. Figure 7 shows pressure versus time. The green line represents the BHP. When the influx was detected three minutes after it started, the subsea pump was set to idle, causing the level and the BHP to increase.

Figure 8: In this kick detection simulation, when the subsea pump is set to idle, it takes less than one minute to stop an influx. This is achieved simply by increasing the mud level in the riser. The well would not have to be closed in to safely stop the inflow.

Figure 8 shows the influx flow rate, total gas volume in the well and LRRS subsea pump rate versus time. Since the subsea return pump was set to keep the riser mud level constant, pump speed has increased by 12% after 2 bbls of influx.

In this case, when the pump is slowed to idle, it will take less than one minute to stop the influx (only by increasing the level in the riser). The total gas volume in the well increases from zero to 67 gal during the four-minute duration of the kick. This equals a PI of 49 stb/d/psi based on 86-ft reservoir exposure.

It can be observed from the simulations that the subsea return pump will give a good indication of a kick. Further, when the kick is detected, the level can be increased to prevent further influx. This is an important benefit compared with a conventional drilling system where further inflow can be safely hindered only by closing in the well. For this specific case, there is still a large pressure adjustment available to the level in the marine riser to give a BHP that is safely above the pore pressure.

Conclusions

LRRS allows the mud gradient to better fit into the operating window in deep to medium-deep water and can reduce the risk of an influx or loss. The system can also improve kick detection and reduce kick size, as well as improve quality of primary cementing. As a result, this technology can improve safety in drilling of deepwater wells and infill drilling in depleted fields.

IADC/SPE 143095, “Well Control When Drilling with a Partly Evacuated Marine Drilling Riser,” was presented at the 2011 IADC/SPE Managed Pressure Drilling and Underbalanced Operations Conference, Denver, Colo., 5-6 April.

References:

1. BP incident investigation team, Deepwater_Horizon_Accident_Investigation_Report.pdf, BP, 8 September 2010.

2. Emilsen et al (Add Wellflow), Report-Dynamic Simulations Deepwater Horizon Incident BP, Appendix W of Deepwater_ Horizon_Accident_Investigation_Report.pdf, BP, 29 August 2010.

3. Halliburton, HAL-Production.Casing.Design.Report.4.15.2010.moderate.pdf, BP, 15 April 2010.

4. Børre Fossli, Ocean Riser Systems, Sigbjørn Sangesland, NTNU; Drilling and Well Control Procedures using a partially evacuated Marine Drilling Riser; IADC Well Control Europe, Aberdeen 13-14 April 2010.

5. Børre Fossli et al, Well Control Procedures in Subsea Drilling Using a Partly Evacuated Marine Drilling Riser, IADC Well Control Asia Pacific, November 2009, Thailand.

EDC’s Rig 52 works onshore Egypt, where utilization is firming up.

Situated at the crossroads of Europe, Africa and Asia, the Mediterranean is a microcosm of how geopolitical and economic events can impact oil and gas recovery. From North Africa to Central Europe, the resource-rich but politically evolving region has seen its share of political tension over the decades.

This year, the story has been the Arab Spring, with the uprisings in Egypt and Libya resulting in drilling and production disruptions. In Libya, especially, the impact of the prolonged political unrest on production was immediate and profound as drilling came to a standstill.

Looking ahead to 2012, operators and drilling contractors are anticipating a market rebound in these two pivotal North African countries. Egypt is returning to production, and the expected stabilization in Libya has raised hopes there for renewed activity. Those developments, along with increased activity in some of the region’s growing markets such as Tunisia and Central Europe, are putting a generally positive spin on the near-term drilling outlook.

“The political situation is stabilizing, and we are very optimistic going forward,” said Jens Byrialsen, managing director of Egyptian Drilling Company(EDC).

Offshore, the Mediterranean is still oversupplied with jackups. EDC’s Setty jackup mobilized out of the Mediterranean in July to Gabon, where it has a three-year contract.

“Onshore, we are seeing dayrates increasing slightly, and utilization is firming up. Egypt has seen some very significant oil and gas discoveries recently that will strengthen that market and attract more companies.

“In Libya, depending on how quickly the political situation is resolved, the potential is there, and we are hopeful we can get our rigs up and running,” Mr Byrialsen continued. EDC shut down and evacuated all three of its onshore rigs in Libya. The company also has one land rig operating in Syria, and while operations have remained steady, Mr Byrialsen is concerned about potential political unrest in that country as well.

Egypt and Libya will be key growth areas for the Mediterranean, along with some emerging smaller markets, he said.

The company has a fleet of 70 rigs, most of them operating onshore Egypt. The offshore rigs include eight jackups, five of which are EDC-owned, and three are under management contracts for Maersk Oil and the Egyptian Natural Gas Holding Company (EGAS). Six jackups are operating in Egypt; the other two are in Gabon and Qatar.

Offshore, dayrates have struggled to keep up, in part because the region remains oversupplied with jackups, Mr Byrialsen said. “Even some reasonably high-spec jackups are sitting idly in the Mediterranean. In the Gulf of Suez, dayrates have softened in recent years, and they remain soft with no indication of an increase.” At the same time, the market will likely have to phase out a significant number of older jackups, he noted.

Complicating the jackup picture is the shrinking shallow-water opportunities in Egypt. “The Egyptian part of the Mediterranean is where we expect to see a serious increase in activity,” Mr Byrialsen said. EDC has no plans to move into the deepwater sector or to add any newbuilds to the jackup fleet.

CROSCO’s Emsco 605 rig will work for Bankers Petroleum in Albania’s Patos-Marinza field.

Another company preparing for an uptick in the wake of Arab Spring is Croatia-based CROSCO, an onshore and offshore integrated drilling and well services contractor. “The return of the North African markets to full capacity will be the biggest development for us over the next 48 months,” said George Kovacic, a consultant for the company.

“Events have happened quickly on both sides of the disruption,” he said. “Within a two-week period, there was an oversupply of jackups in the region, and now, in another two-week period, we have seen that oversupply balance out. The planned, ongoing projects will be the first operations back on track.”

The company, with its subsidiary Rotary Drilling Company, has more than 50 land drilling, working and geoservices rigs, one jackup and one semisubmersible. Several are working in the Mediterranean region.

Those include three drilling rigs under contract in Libya. All three were shut down in March. CROSCO also has two owned and one managed rig in Egypt and has plans to move into Tunisia. The first of the drilling rigs in Egypt, the EMSCO 605, is already being mobilized back to work following the disruption in that country. The company also has an ongoing operation in Turkey.

The North African market is rich in oil but also exports a large amount of natural gas to Europe, Mr Kovacic said. Italy has long-term natural gas contracts with both Libya and Algeria.

CROSCO’s ZAGREB 1, a semi that has been active in the Mediterranean, will be available in early 2012 after undergoing a five-year survey and maintenance program.

“We’re feeling very positive about the future,” Mr Kovacic said. “A healthy market in the region is in everyone’s best interest. Everyone needs the revenue that will be generated.”

Adriatic and the Balkans

CROSCO has extensive operations along Adriatic coastal and Balkan nations, with ongoing drilling and well services operations in Croatia, Hungary, Bosnia-Herzegovina and Slovenia, and a jackup in Italy, where the company held, and may still hold, the record for the deepest offshore well drilled in Europe, at nearly 24,000 ft.

ZAGREB 1, a semisubmersible that has been active in the Mediterranean region, is undergoing a five-year survey and maintenance program and will be available in January 2012. CROSCO also anticipates an increase in operational activities in Croatia.

Given the complexity of the Albanian region, Bankers Petroleum is using a thermal pilot drilling program to navigate the field.

The company’s most prolific Central European operation is in Albania, where it has two rigs operating – and will be deploying a third – for Bankers Petroleum in the Patos-Marinza field, the largest onshore oilfield in continental Europe, with an estimated 7.5 billion barrels of oil in place.

The field produces primarily medium- to heavy-grade oil with an average API of 8° to 10°, said Gregor Schoenberg, senior staff drilling engineer for Bankers Petroleum. Since the company entered the Albanian market in 2004, production has gone from 600 bbl/day to 14,000 bbl/day. Production, most of it for export, has increased by approximately 75% in the past 18 months.

“We’re bringing Western technology and expertise into an area that was initially drilled and produced using very rudimentary methods” Mr Schoenberg said. “We are much more efficient because we have science on our side; we are also much more environmentally conscious.”

Vertical drilling has been done in the field since the 1920s, but production had declined to very low levels prior to Bankers’ commencement of operations in the country. The Albanian government has been very receptive to the influx of Western technology, and the ramped-up production has been good for the local economy, Mr Schoenberg added.

This Bankers Petroleum map shows the Patos-Marinza field’s current export markets. The field is the largest onshore oilfield in continental Europe, with an estimated 7.5 billion barrels of oil in place.

Bankers, using older rigs that have been modernized, now has four rigs operating in the field, drilling eight horizontal wells per month. A fifth rig, which is being supplied by CROSCO, will begin service in November and will help push the number of new horizontal producers per month to 10. Measured drilling depths are typically 2,500 meters, with 500- to 700-meter horizontal legs. The reservoirs feature multiple layers in three zones – the upper Gorani zone, middle Driza zone and Marinza – each with several sub-sections.

Thermal drilling pilot

“These are not cookie-cutter wells,” Mr Schoenberg said. “The region is geologically very complex, with layers that come and go throughout the field, making it technically challenging to navigate. One of the biggest challenges for us is avoiding the existing vertical wells that were drilled in the past.”

KCA DEUTAG’s SPEED RIG, manufactured by subsidiary Bentec, is a lightweight, high-speed compact rig designed to be efficient in desert conditions.

The company recently embarked on a thermal pilot drilling program for some of the heavy oil in place. “We believe there is huge potential in this play for heavy oil production,” Mr Schoenberg said. While the initial pilot uses a “huff and puff” process of alternating steam injection with production, future plans could include a typical steam-assisted gravity draining (SAGD) process.

This involves drilling parallel holes on legs within a few meters of each other and injecting steam into the upper leg. Gravity then pushes the steam down into the production leg to make the fluid flow more easily.

Bankers also has a fleet of 12 service rigs – with plans to bring in two more – for well cleanout, workovers and water shut-off work and is bringing in additional coiled-tubing units. The company also has retained assets in the heavy-oil Kucova field in Albania, which holds an estimated 296 million bbls of oil in place.

KCA DEUTAG, headquartered in Aberdeen, is anticipating strong growth in its onshore business in North Africa following the Arab Spring uprisings, Rodrigo Rendon, head of business development, said. The company owns and operates 16 of the 54 rigs that were working in Libya before the shutdown.

CROSCO’s IDECO 301 mobile rig is operating on the Patos-Marinza oilfield in Albania.

“We successfully and safely evacuated our employees and have kept local security to oversee our rigs in-country, which are located in the desert, somehow away from the main areas of unrest,” Mr Rendon said. “The timetable is difficult to pin down, but we anticipate a return to some kind of activity in 2012.”

Algerian market growing

The company also has three rigs active in Algeria that are working, among others, for Dublin-based Petroceltic International, and plans to double the count next year with the introduction of three additional newbuild rigs. “We see Algeria as a growing market,” Mr Rendon said. “The country has large proven oil and gas reserves and is a major supplier to Europe. We are also working at further enhancing our relationship with Sonatrach, the Algerian-owned oil and gas company.”

The increase in activity will involve deployment of the SPEED RIG, primarily 1,500 hp, manufactured by KCA DEUTAG subsidiary BENTEC. The AC-driven, lightweight, compact rig was designed to be highly efficient in desert conditions. It features a 36-hr move time between wells and a top drive with 25% higher torque than equivalent models, according to the company.

KCA DEUTAG’s Rig T-212 is operating in Algeria. The company has three rigs active in Algeria and plans to double its rig count there next year with three newbuilds.

KCA DEUTAG also is exploring the possibilities of entering the other markets and countries and regions in Africa where it currently does not have a footprint, for example, in East Africa and Tunisia. The company has appointed Stuart Anderson as business development manager for Africa. “We are offering a proposition of quality and performance to ensure that our clients are able to drill their wells safer, quicker and in a cost-effective manner,” Mr Anderson said.

The main challenges in the region include security and limited rig capacity, meaning the demand is far greater than the supply. Also of top priority is ongoing development of relationships with the national oil companies and international players, he noted.

In the offshore arena, Grup Servicii Petroliere (GSP), a subsidiary of Romania-based Upetrom Group, provides drilling and construction services in the Black Sea and Mediterranean Sea. The company owns a fleet of seven jackups that have been modernized in the last three years, Bruno Siefken, senior vice president of Upetrom Group, said.

Black Sea challenges

“Most of the drilling we do is conventional, but the Black Sea has some deepwater high-pressure, high-temperature (HPHT) wells, and we have future plans to add a semisubmersible to the fleet to move into deeper waters,” Mr Siefken continued.

GSP was the general contractor for the Engineering, Procurement, Installation and Commissioning (EPIC) project for TPAO, Turkey’s national oil and gas company. The company recently completed drilling four wells with a platform rig in the Akcakoca gas field of the Black Sea, about 150 km from Istanbul.

GSP hopes to relocate that rig to Greece to drill and work on 10 exploratory wells for Energean Oil Company in the Kavala oil and gas field, pending the resolution of that country’s financial debt crisis, Mr Siefken said. In addition, Energean is planning several exploration wells.

GSP’s Bigfoot 3 is working for the Akcakoca Project in the Black Sea.

GSP has two jackups in the Black Sea, one that is being refurbished and another that is set to begin drilling an exploration well in offshore European Turkey. GSP Saturn, another jackup that was rebuilt in 2009, has been deployed to Kaboudia field in Tunisia for Numhyd.

“We have established a base in Tunisia and from there plan to expand into other North African countries, mainly Libya, as soon as that market comes back online,” Mr Siefken said. “We feel that with the formation of new governments in Egypt and Libya, offshore drilling activity will rebound stronger than before.” Prior to the Arab Spring, GSP had one rig operating in Libya for Japanese oil company JAPEX.

GSP’s jackup design allows for easy mobility between the Black Sea and Mediterranean Sea through the Bosphorus Strait. “Our rigs have leg extensions that can be mechanically disconnected to clear the bridges in Istanbul, that are only 58 meters high,” Mr Siefken said. “We can take 15 meters off our rig height. This technology gives us the advantage of moving between the two seas in a cost-effective way, providing us a high rig occupation rate.”

ENSCO 5006, a deepwater semisubmersible with 6,000-ft capability, is working in Israel. There is an increasing demand for deepwater-moored semis in the Eastern Mediterranean, said Steven Brady, Ensco vice president, Europe and Mediterranean.

Ensco has had jackups operating in shallow water off Tunisia for some time, said Steven Brady, vice president, Europe and Mediterranean. The ENSCO 85, a 300-ft MLT 116-C jackup, is working for PA Resources, a Swedish oil and gas operator. Through its acquisition of Pride International earlier this year, Ensco also has a deepwater semisubmersible working for Noble Energy offshore Israel.

“Some world-class gas reserves have been found in the region, and there is optimism that this trend will bring significant drilling opportunities,” Mr Brady said. Ensco has not been significantly impacted by the events of the Arab Spring. “We were careful to quickly institute safety measures when some of the uprisings began several months to protect our people and assets,” he added.

“But for some of the uprisings and the Greek debt crisis, we might have had more demand for offshore rigs in Libya and also Greece, where we have contracted some of our jackups for Aegean Energy; however, that is hard to quantify,” he continued. “As the situation in Libya and the broader region stabilizes, we hope to see more opportunities with customers.”

Deep and HPHT environments are among the technical challenges in the region. “There are some unique drilling challenges in the Nile Delta area where Egyptian operators have some deep, high-pressure gas work requiring HPHT-capable and experienced rigs with two million-lb hookload capacity,” Mr Brady said. “Also, we are seeing increasing demand for a deepwater-moored semi with 6,000-ft capability such as the ENSCO 5006 in the Eastern Mediterranean, in offshore Egypt, Israel and Cyprus.”

SPEED RIG is a trademark of KCA DEUTAG/Bentec.

Figure 1: The blowout incident management can be divided into two major phases: the first immediate response and the continued response. If the first response fails to produce results, a continued response mode is implemented.

Petrobras uses Incident Command System to plan for first, continued responses in worst-case well control scenarios

By Frederico de Azevedo Maia, Fernanda Azevedo Cavalcante Fernandes, Alfonso Humberto Celia Silva, Petrobras

To establish an effective blowout response, drilling hazards must be assessed. Once the potential hazards are understood, it is logical to recognize that blowouts are the most important hazard during the well construction process to be considered. This article describes how Petrobras is approaching blowout response.

Along with comprehending well-construction hazards, the first steps to understanding blowouts means establishing a way to reduce risks by running a hazard assessment during the well design phase.

Important characteristics to consider are:

• Geological aspects;

• Properties associated with the production of each geologic zone;

• Fluid properties, fluid pressures in each zone, types of fluid (oil, gas, contaminants), plus water, sand and other toxic elements that may be present; and

• The structural density of each zone and abnormal characteristics.

Operational aspects that should be considered are:

• Drilling rig limitations, including capabilities as far as pump pressure and flow, maximum well depth, corrosion and erosion protection on lines and accessories, critical supplies and spare parts, flare locations, maximum BOP pressure, and how to identify gas presence and abnormal flow in the drilling fluid;

• Well design critical points, including what could go wrong and how to return to normal operations, what kind of well logging (define the range) needs special attention and what to do for each case during the critical stage of well construction, as well as pre-planning a relief well (location, drilling rig and supplies).

• Minimum rig team qualifications to understand risk-control actions associated with well design;

• Pre-job meeting to discuss all critical tasks with the team;

• Safety job assessment to ensure critical jobs have procedures with safety points; and

• Understanding the emergency response plan (ERP) is a must for the rig operation team; this understanding would be useful to all other personnel on the rig as well.

Once these considerations are made and the potential hazards are understood, we must look at the problem itself – the blowout. The first step is to understand the blowout process: If you know how blowouts develop, it would be easier to establish measures to control them.

To achieve this understanding, it is necessary to identify the average timeline when control of the well is lost. This timeline represents well behavior in blowout conditions.

In this step, the blowout growth path and its critical points must be identified. To identify these critical points is to consider the points that could lead to a worst-case scenario and consider them critical. The interactions of each point with all other identified points should then be assessed. This assessment should identify the root causes of each critical point and its interactions with others; this makes it possible to take the measures necessary to prevent or reduce their effects, as well as the effects of their interaction.

Once the root cause and consequences are established, a determination can be made as to what competencies and capabilities will be required of the people involved in order to establish correct procedures and associated resources (personnel, equipment and supplies) to control each critical point.

The Incident Command System (ICS) protocol is an important tool that can be used to solve this complex problem (variable numbers, competencies and capabilities of personnel involved at different points of the incident timeline). The ICS organization chart and communication system determine the organization and resources that would be needed to run an orchestrated response to an incident.

Figure 2: Petrobras’ emergency organization chart is used to support a blowout response. Executing a plan of action begins with the rig team (yellow boxes). If the incident escalates, the company man and BOP “ERBO” team are added.

The blowout incident management is divided into two phases:

• Immediate response – where all procedures must be correctly undertaken by the rig floor team, and they must react immediately.

• If the first response does not achieve the desired results and the incident dynamics continue to escalate, a continued response mode shall be implemented. The principal steps to improve continued-response management are:

o Assess the incident – what are the problems and the probable paths of incident escalation;

o Set an incident action plan (IAP) – what needs to be done immediately after first response to control the situation and to prevent incident escalation;

o Take actions to apply these plans;

o Consider the planning, logistics, and administrative and finance aspects;

o Use a communication system to exchange information and make a critical evaluation of the incident action plan’s effectiveness;

o The post-incident plan is not within the scope of this article.

Kick signals

To react as soon as possible to a blowout, the entire drilling rig team must work to identify kick signals. The sooner the signals are identified, the easier the well could be controlled. Decisions must be taken by the drilling team to control a kick without delay because the window of time for the correction is very small.

The most common cause of inflows is the loss of the first inflow barrier – drilling fluid hydrostatic pressure is less than the formation pressure. The driller must observe the values of the variables, defined in the well design; if the levels are beyond the set limits, the well is likely taking a kick. Depending on how far beyond the parameters and which stage of well construction is under way, it can be easy to re-establish the wellbore equilibrium pressure and prevent a blowout.

Another consideration is the well shut-in consequences. If the wellhead safety devices (WHSD) stop the flow and the pressures in the wellhead are controlled to an acceptable level, the well is controlled and the next step is to establish the tie-back to kill it.

However, if, instead of stopping the flow, there is a failure in the WHSD (leakages) or if it is necessary to reduce the wellhead pressure to prevent an underground blowout (casing shoe or cementing limit pressures exceeded), the situation becomes much more difficult to control. In this case, it is necessary to establish countermeasures to reduce these pressures. Such countermeasures may involve complex procedures and additional resources to maintain the well pressure relief flow without fluids leakage to the atmosphere or environment.

As all initial procedures to shut in the well are set by the first-response plan (FRP), it’s critical that all procedures and resources are included in the FRP. All resources listed must remain mobilized and ready for use.

The FRP makes up the basis for the training of the rig team, especially the operations group.

Once drill exercises and audits (on the integrity inspection and maintenance program) are run, it is assumed that the FRP is capable of efficiently controlling the incident. In case any doubts arise about its efficiency during the drills, FRP reviews shall be made.

Figure 3 shows the application of the Incident Command System in an incident escalation flow. The first steps involve application of the first-response plan.

Applying ICS

Once well-kill procedures are completed, the incident is solved; however, it is easy to recognize the complexity of customized procedures, operations, resources and, most importantly, the specialized personnel that set and execute these procedures and their support accessories.

Again, the ICS becomes an important tool to guarantee that all objectives are efficiently attended. This emergency management protocol establishes an array of hierarchy and duties, as well as its capabilities, responsibilities, registers, documentation and communications flow.

The ICS protocol is useful from small occurrences to big incidents such as Macondo. It could be adapted to any incident condition and could be used in escalating situations or after-incident control when the situation is normalized.

Figure 2 shows the Petrobras emergency organization chart (EOC) that is run to support a blowout response. The ICS chart has been simplified, with the command and support sections (logistics, and administration and finance) excluded. In a real application, these shall be considered.

Figure 4: In applying the ICS protocol, three goals are involved: to evaluate the objectives and their defined strategies, to identify the necessary related tactical-response actions, and to plan the tactical actions that attend the strategies. These tactical actions may include timing, resources and supplies.

Under the operations section, executing the plans begins with the drilling rig team (the yellow boxes). If the incident escalates, the company man and an “ERBO” team (Portuguese for blowout response “transpire” team) are added. This could be a specialized team or a single person linked directly to the planning section to execute the procedures established in the ERP’s first-response plan or continued-response plan (incident action plan).

Simultaneously, the HSE team works with the emergency team to apply safety countermeasures supporting the rig team’s actions.

The planning section is where, after the first response, the IAP will be established and revised after each critical analysis of its effectiveness. After the blowout behavior is identified, it is necessary to then identify the personnel competencies needed to produce an IAP in accordance with the incident dynamics. Often, the company will need to deploy competencies and capabilities from different assets and maybe even from another country. The goal is to associate all the necessary and high-level knowledge and know-how to develop the best IAP within the time and information available at the moment.

Figure 5: The two meetings and one planning session dictated in the ICS management flow are not necessarily executed separately. Depending on the incident dynamics, the team may realize these steps in one operation or work session.

At Petrobras, this specialized group is called CARBO, which in Portuguese means blowout coordinator support team. This team is made up of specialists ranging from engineers and well designers from operational units to top well research engineers from CENPES, Petrobras’ research center. With this group, Petrobras is capable of setting an adequate IAP to support the ERBO team on the drilling rig.

Figure 3 shows an example of applying the ICS in a typical incident escalation flow. The first two steps represent application of the FRP. The on-site personnel immediately use their capabilities, acquired through training, in this initial phase. In this example, a small abnormal situation is controlled by one employee – this represents the operational response in a basic case. For the first response to be effective, it is important that the procedures are applied and that all associated resources are ready for use.

A part of the first-response procedures is to trigger the next phase – the continued-response management – if more resources are needed. This is accomplished through an alarm system.

This phase begins with the first-command staff meeting to evaluate the effectiveness of the first response and determine if the FRP procedures should be revised or if the first IAP needs elaboration. To conduct this meeting, information that was registered (formal and mentally) by the first-response team must be communicated; this is part of the ERP. If the incident scene was identified and is part of the scenarios foreseen in the ERP, this information will be used to support the first meeting.

During this meeting, the commander defines the objectives and the most important strategies that guide the response effort. In this sequence, if the first response is effective, the incident is controlled and eliminated.

Yet if the incident continues, the response actions that are being applied should be reviewed, and new response actions may need to be established.

Figure 6: Strategic actions to take, once agreed on by all the disciplines, are submitted to the command staff so they can establish tactical options. A new meeting may be needed if no agreement is reached on what strategies to take.

In applying the ICS protocol (Figure 6), the goals are:

• To evaluate the objectives and their defined strategies;

• To identify the necessary related tactical-response actions;

• To plan the tactical action (timing, resources and supplies) that attend the strategies to achieve the objectives.

Three tasks are planned – two meetings and a work planning session. The first meeting aims to define the response in a broader sense (legislation compliance, difficulties, gross resources and supplies that need to be associated). The next meeting will define in more detail what tactics are associated with the identified strategy and how they could be applied (procedures and resources).

Once the tactical actions and their operational procedures are established, the resources needed to allow their effective execution must be planned. All resources and associated supplies will be identified and quantified, with their deployment time and location scheduled.

The logistics section is responsible for ensuring the resources and supplies are available, as well as for their mobilization.

One key point is that these three steps are not necessarily executed separately. Depending on the incident dynamics, the team may realize these steps in one operation or work session.

If the results of the strategic actions are agreed upon by all the necessary disciplines, the command staff establishes the tactical options for each strategy. If the decision to apply these tactics is not reached, the issue is returned for a new objective/strategy meeting that would consider command staff suggestions. If the command staff decides that the defined strategies and tactics can achieve the objectives, then the strategies and tactics will be completed with all the documents and information necessary (to facilitate purchase identification or mobilization from the company warehouse, including outsourcing or personnel qualifications) to deploy them.

After all tactical procedures and their associated resources, including personnel and supplies, are defined, the entirety of this information will be evaluated in a meeting of the command staff with the purpose of securing the commander’s approval of the strategies and tactical actions and the priority of these strategies.

Figure 7: After the tactical actions are approved, they are broken down in detail to be applied.

Once approved by the commander, the tactical actions are broken down by detail to be applied. This includes training personnel and guaranteeing that the logistics team is able to supply the necessary resources for the operational team (Figure 7). The qualifications and level of instruction for the team to be trained should be considered, as well as the training technique to be applied.

Again, these three steps are not necessarily executed separately and may be realize in one operation or work session.

For the resources needed, care must be taken with their transportation. The delivery route and means of transportation of the resources should be defined (from company, warehouse or supplier) so as to guarantee identification, mobilization and deployment at the determined site.

The necessary financial resources shall be available, the cost-control actions shall be in place, and the administrative means to control personnel work hours are set in motion.

As these procedures are running, the task teams must continue to inform their commander, through the hierarchy line, the level of effectiveness or failures of the measures taken. This is important feedback for the management of the incident.

Figure 8: The last step of the ICS management cycle is to evaluate the effectiveness of the response and, if necessary, consider the need for establishing an alternate IAP.

The final step of the ICS management cycle is a diagnosis (Figure 8 ) of the incident response and its effectiveness.

If the incident is not totally resolved, feedback from the operational teams and the IAP are analyzed, and the need for a review or other IAP is considered. A new incident management cycle will be run again.

If the response resolves the incident, all typical response activities are terminated, and the command staff establishes a post-incident plan.

Conclusion

To effectively respond to a blowout or a similar scenario, it is necessary to consider these points:

• Understanding of the incident dynamics and behavior is essential;

• An emergency response plan focusing on the first-response actions and continued-response management must be established.

For continuous-response management, a systematic organization of competencies that could generate a continuous IAP is needed. The ICS protocol perfectly fits the organizational resource management and operational planning needs to attend the objectives of controlling the incident.

This article is based on a presentation at the 2011 IADC Well Control Conference of the Americas Conference & Exhibition, 25-26 August, San Antonio, Texas.

Click here to view the embedded video.

Click here to view the embedded video.

As the 15 November deadline for SEMS compliance on the US OCS approaches, Hercules Offshore will have about 20 rigs operating in the Gulf of Mexico, including the Hercules 173 jackup. Under the OOC SEMS Taskforce, leaders from all facets of the industry contributed to a SEMS toolkit to assist companies in complying.

HOUSTON - Facing an impending deadline, companies from all corners of the industry capitalized on an unprecedented opportunity to help themselves reach a shared goal: to facilitate the safest and most environmentally sound workplace while mitigating the potential dangers inherent to drilling operations.

The US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) – recently replaced by the Bureau of Safety and Environmental Enforcement (BSEE) – announced in October 2010 mandatory practices required to operate on the US Outer Continental Shelf (OCS). The 15 November 2011 deadline gave the industry little more than a year to complete what initially seemed like an insurmountable task: comply with BOEMRE’s call to implement a mandatory safety and environmental management system (SEMS), a program that operators are required to develop and maintain with the cooperation of contractors and other third-party service providers.

Although the use of a safety and environmental management system is not a new idea, the regulatory mandate sent waves through the industry; the considerable task was going to require more than a revision in protocols. “SEMS had its first place in the Gulf of Mexico as API RP 75 (SEMP) in the early ’90s. It was a voluntary program at that time,” Bill Walker, HSSE adviser at Cobalt International Energy, said. “The concept is not radical or new.”

Rowan Companies’ crewmen review paperwork before beginning a job on the EXL I high-specification jackup, which is drilling for McMoRan in the Gulf of Mexico. Among changes to existing elements and additional requirements, SEMS II proposes a formal approval of all job safety analyses.

With the support of the Offshore Operators Committee (OOC), the Center for Offshore Safety (COS) and IADC, in conjunction with leaders from oil and gas companies, drilling contractors and other contractor companies, the industry united to create a thoroughly SEMS-compliant environment. A collaborative effort was forged to create a SEMS toolkit to advance E&P activities on the OCS. “With the lessons that we have learned from the offshore disasters, we will continue to make a difference in safety,” Jack Isbell, safety specialist at Rowan Companies, said. He participated in the SEMS Taskforce Competence Subcommittee and in developing the SEMS Compliance Readiness Worksheet. “The SEMS is an effective method for making that difference. It’s a more systematic way to work safely and protect the environment, and when you have a lot of very complex systems working, that systematic method is necessary.”

The implementation process cultivated not only the collaboration of various departments within each company but also among competitors. An expansive task force emerged from a modest meeting of seven people from different companies in February, but without a sponsor. At a second meeting in March, the OOC stepped up to sponsor the group, which then facilitated a number of meetings and the formation of subcommittees addressing different aspects of SEMS implementation. By June, about 150 people from all facets of the industry were participating on the OOC SEMS Taskforce, which went on to create the SEMS Toolkit.

The introduction of SEMS regulations to the US OCS is a process that is still unfolding. Implementation of a SEMS program was just one major variable that operators and contractors had to overcome; moreover, the industry is subject to government interpretation and revisions of the regulation, which could call for further cooperation within a highly competitive industry.

On top of that, the recently proposed SEMS II, which modifies and adds to the current regulation, will create its own challenges. Among other things, the new proposal calls for: mandatory third-party audits, providing all workers with stop work authority, documenting employee participation in SEMS development, formal approval of all job safety analyses, designation of an individual having “ultimate work authority” and guidelines to report of unsafe working conditions. The comment period on the proposed rule closes 14 November, and a final rule isn’t expected until spring 2012 or later.

What is SEMS?

In 1994, the then-Minerals Management Service (MMS) recognized API RP 75 to fulfill the principles of a safety and environmental management program. Oil and gas companies operating on the OCS were encouraged to voluntarily adopt the recommended practice, which was intended to reduce the risk and occurrence of accidents and pollution on offshore oil and gas drilling and production facilities. Regulators identified four elements of the original 12 elements of RP 75 that were necessary in an effective program, based on incident investigations and performance reviews with operators.

The SEMS final rule includes API RP 75’s 12 sections and an additional section to address the responsibilities of companies’ general management. The rule applies to current and future OCS operations and facilities under the jurisdiction of the US Bureau of Safety and Environmental Enforcement.

In 2009, the then-MMS proposed a rule to mandate that leaseholder/operator management systems include those four elements: hazard analysis, management of change, operating procedures and mechanical integrity. “Prior to 2010, BOEMRE looked at regulating four of the now-13 requirements,” said IADC industry compliance specialist Julia Swindle, who has been participating in the development of the SEMS Toolkit under the OOC SEMS Taskforce. “Then Macondo happened, and now they’re including all 13,” she said. An additional section was added to the original 12 elements to address the responsibilities of companies’ general management.

The October 2010 SEMS final rule, which includes API RP 75’s 12 sections, applies to current and future OCS operations and facilities under BSEE’s jurisdiction, including drilling, production, construction, well workover, well completion and well servicing. BSEE and the Bureau of Ocean Energy Management (BOEM) replaced BOEMRE on 1 October.

Operators are responsible for having a SEMS in place, and contractors need to be prepared to respond. “Although contractors are not required to have a SEMS for their own operations, their cooperation is necessary for operators to be in compliance; therefore, it is in contractors’ best interest to anticipate operators’ needs and proactively cooperate with operators,” Dr Brenda Kelly, IADC senior director of accreditation and certification, explained. Dr Kelly leads the SEMS Competence Subcommittee under the OOC SEMS Taskforce. Under the final rule, each operator needs a written agreement with each contractor they are working with to document safety and environmental policies and practices.

“Part of the challenge is that although operators must comply with the BSEE regulations, they can interpret how to satisfy them. A contractor must be prepared to follow the operator’s SEMS program,” Dr Kelly said. One benefit of SEMS is that all companies will be held to the same minimum standard, Ms Swindle added. “It is a system that will hold all lessee/operators and, by default, contractors on the OCS to the same requirements and level the playing field,” Ms Swindle said.

IADC HSE Case Guidelines

Recognizing that many members had based their SEMS on the management system guidance provided in the IADC HSE Case Guidelines for MODUs, IADC performed a gap analysis of the guidelines against API RP 75 and the BOEMRE Final Rule.

The results of the gap analysis were made available to members in early 2011, according to Alan Spackman, IADC vice president – offshore technical and regulatory affairs. “The analysis found only minor gaps,” Mr Spackman said, “and these were formally closed with the adoption of amendments to the HSE Case Guidelines for MODUs in October 2011.

Rowan Companies’ Ralph Coffman jackup is contracted to work for McMoRan in the Gulf of Mexico. For SEMS compliance, it is in contractors’ best interest to cooperate with operators, who are responsible for meeting the requirements of the mandatory regulation. In preparation to meet operators’ requirements of contractors, Rowan has conducted on-site training on rigs, and training courses are being revised to take SEMS into account.

Implementation

Some contractors initially reacted to BOEMRE’s announcement in October 2010 with a wait-and-see approach. However, some also found that their existing safety and environmental management programs paralleled the new regulations. “Having had a SEMS for a number of years and, at the time, being in the process of revising it to meet stricter safety standards, I felt that we were in a good place,” Mr Isbell said.

Jennifer May, director corporate HSE and management system for Hercules Offshore, expressed a similar sentiment and noted that Hercules has had a safety and environmental management system in place since 2007. “We did a gap analysis, and we were very fortunate to find we didn’t have very many gaps,” Ms May, who is a member of the SEMS Taskforce Contractor Guidance Subcommittee, said. “What it has brought to the surface is the execution piece. On paper, people have great systems, great policies, but it’s getting those policies into the hands of the rig crews and getting them to embrace it and use it. That’s the struggle.”

Translating a policy into everyday practice entailed significant time and resources over the past year. “Our engineering department has had a team working on SEMS. Our operations department has a compliance team working on SEMS. HR, training, all the departments that make this company operate have had dedicated personnel on the SEMS implementation,” Ms May said. While the interpretation of the regulation began to take shape through discussions and drafted policies, contractors and operators continued the implementation process through practice and execution in the form of training sessions. “We’ve spent a lot of face time with the rig crews,” she added.

Rowan hosted two SEMS-specific training sessions at Houston’s Hotel Derek in October, specifically for rig supervisors, offshore installation managers, engineers and HSE technicians. “The management system can be that transfer of experience and understanding that can be done off-site. Are we going to be able to slip and cut drill line at a hotel? Not quite, but we can ensure that they understand how the new rule and its intent will make their rig a safer place,” Mr Isbell said. “They will be able to take the information and apply that logic and understanding to the individual jobs and to the task of slip and cut drill lines.”

Rowan also conducted on-site training on rigs, and training courses for new-hires are being revised to take SEMS into account.

Mr Isbell pointed to the necessity of supervisors’ leadership in building support for and compliance with SEMS. “As great as a training or class may be, the key to the proper use of the management system will be in our supervisors and their continued support of the SEMS,” he said.

A floorman works on Rowan’s EXL III jackup, which also is drilling for McMoRan in the GOM. SEMS II proposes to provide workers with stop work authority and for companies to develop guidelines for workers to report unsafe working conditions. The comment period for SEMS II ends 14 November.

Operators’ involvement

While contractors have a sense of the general requirements that are necessary for compliance, operators’ requirements can vary. Fortunately, Rowan has encountered some common ground among its customers. “(Operators) have been fairly uniform with the requirements and expectations. I think that we have the work of the API, the OOC and IADC to thank for making sure that, of 10 different operators, there are not 10 different sets of expectations,” Mr Isbell said.

Communication also has been a constant key to success in SEMS implementation. “The relationship between the operator, the service contractor and the drilling contractor requires a lot of communication, and SEMS just underscores that and brought it to the surface in the form of a regulation,” Mr Walker noted.

Although the SEMS Taskforce initiative began with operators, they realized that compliance would require cooperation from their contractors. “When the group got together, it was a group of operators,” Ms Swindle said, “but they realized that this was a bigger challenge that would require the cooperation of the contract companies that they work with and that, they being responsible (to meet the requirements), needed to help provide guidance for the drilling contractors.”

The SEMS Taskforce brought together leaders from supermajors and other independent operators: Anadarko Petroleum, BHP Billiton, Chevron, Cobalt and ExxonMobil, as well as from the contractor community, such as Ensco, Hercules, Noble Corp, Rowan and Transocean. Baker Hughes also contributed to the toolkit.

Mr Walker, who chaired the Documents and Data Subcommittee, noted the benefit of the joint effort. “The more conformity we can bring to the process, the less work and expenses will be associated with the contractor providing information,” he said. “We worked on safety questionnaires, letters of agreement, and we’re working on other areas where we can make this a more efficient transfer of information or communication between the operator and drilling contractor.”

Most of the toolkit is geared to aid drilling contractors. “The SEMS toolkit was developed as a cooperative effort with over 50 different companies from all different sectors of the oil and gas industry,” Ms Swindle, who helped compose the compliance readiness worksheet, said. “A lot of really smart people contributed to that effort.”

Subcommittees within the taskforce created worksheets, templates and guides ranging from SEMS audit protocol and training matrices to documentation worksheets and agreement letter templates. The extensive toolkit, which also includes PowerPoint presentations and a list of definitions with examples, is available for free on IADC’s website at www.iadc.org.

The operators’ involvement in the taskforce has created cohesiveness in the industrywide effort and sets a foundation for continual improvement. “It is a continual implementation and audit process that they’re engaged in,” Mr Isbell said. “They are being very cooperative in saying ‘let’s make sure we have all the requirements met, and how can we go above and beyond the minimal requirements and exceed expectations?’ “

In conjunction with drilling contractors’ SEMS training, Cobalt is also implementing a program for anyone – employees, contractors or visitors – to complete a SEMS orientation conducted by Cobalt rig personnel and HSE advisers. The goal is to make everyone “aware of how SEMS is impacting our day-to-day activities on the rig,” Mr Walker said.

Contractors might consider SEMS in the future construction of rigs. Rowan’s Joe Douglas jackup was under construction as the company was in the process of implementing SEMS. The contractor found it necessary to request certain inspections or certifications earlier to meet requirements.

Effects/outlook of SEMS

Embarking on a SEMS-compliant industry, the path remains bumpy for all parties involved. Although many contractors and operators began compliance efforts more than a year ago, “nobody can guarantee they will be in compliance” until BSEE performs an audit, Ms Swindle stated. “BOEMRE made it clear that they want to use auditors that do not have any conflicts of interest, but it seems the only way to do that may be to go outside of the industry. It’s going to be a huge learning curve for everybody.”

Mr Walker agreed that challenges might surface from BSEE’s interpretation of the SEMS language. “Our approach is to do our due diligence to implement, to the best of our abilities, all of SEMS, and then as we receive guidance, we will make accommodations for any changes that may be needed,” he said.

Some contractors remain optimistic in overcoming obstacles and in maintaining a joint effort with operators. “We will take any cases, where shortcomings have been identified, as opportunities to grow, revise, implement and evaluate changes to improve our management system,” Mr Isbell said. “There are going to be some growing pains.”

Because many contractors and operators who operate on the OCS also operate in other drilling markets, the lessons learned from mandatory SEMS implementation in the US are making their way around the world. “Our management system that’s compliant to SEMS is already corporation-wide,” Ms May said, putting SEMS into play onshore the US and on Hercules’ rigs in the Middle East, Africa and Southeast Asia. “For consistency sake, it’s better to have one management system that meets industry best practice.” Rowan also uses SEMS through all operations, including on rigs in the Middle East, Southeast Asia and the North Sea.

Cobalt’s SEMS-compliant HSE management system is also global. “The only caveat is if we are working in a part of the world where, for whatever reasons, regulatory or logistically, there’s some part of our HSE management system that cannot be directly applied,” Mr Walker said. “We might have to make some adjustments to it, but we will not in any case work in a downgraded situation.”

For companies based outside the US or not operating on the US OCS, some industry leaders foresee SEMS or similar programs becoming a reality for them as well. “I am fairly confident that the companies that operate in those regions will have adopted either the requirements that you see here in the Gulf of Mexico or some very similar,” Mr Isbell said. “It’s been said that ‘as goes the Gulf of Mexico, so goes the rest of the industry.’ A lot of that is because the Gulf of Mexico is an excellent training ground and excellent place for development of leadership.”

Future construction of rigs might also take into consideration the SEMS-compliant environments in which they will enter. Rowan’s construction of the Joe Douglas jackup was under way as the company was in the process of implementing SEMS. Given the company’s initial system that was largely already compliant with SEMS, the jackup did not face additional hurdles, but the contractor did move up some parts of the SEMS process.

“We needed to request certain inspections or certifications sooner, whereas we might have been able to have waited until ‘X’ number of months before the rig went to work to request a certain inspection or certification,” Mr Isbell said. “It helped us to be more prepared, and be more prepared earlier.”

The driving forces behind SEMS implementation can be traced back to the priorities of the program: human life and the environment. While it is not possible to quantify the value of the program, SEMS is intended to promote a high-quality workplace to avoid accidents that could result in injuries to personnel and environmental consequences. “If (SEMS) is utilized, it can’t help but have a positive difference on the rig, and you will see it. It’s a trickle-down effect,” Ms May said. “You’ll see efficiencies such as higher productivity, less downtime, overall quality, less property damage and fewer incidents because people are using it.”

Conclusion

An event of alarming magnitude might instigate the establishment of preventive measures, but the utilization of those practices is just as important. “The most significant regulatory change in our industry has been from Piper Alpha and now Macondo,” Ms May said. “However, legislation in and of itself is not the complete answer. We must consistently and persistently do the things that we say we are going to do as provided in a management system to ensure incident-free operations.”

Legislation and, more importantly, the industry’s united front are transforming the drilling environment into a safer one. “I think the participation that we had (in the SEMS Taskforce) was excellent and really precedent-setting for this industry. This is a very competitive industry, and a lot of companies are careful to maintain what they consider to be their competitive edge,” Ms Swindle said.

The deadline to implement SEMS might come and go without much fanfare, but the date marks the beginning of a new era for the industry. “15 November will be the first day of a new era in safety and environmental management in the Gulf of Mexico and other places under BOEM jurisdiction,” Mr Isbell said. “It’s a new era in safety and protection of the environment.”

Rowan Companies’ Jack Isbell and IADC’s Brenda Kelly and Julia Swindle address industry challenges and initiatives related to the SEMS regulations in exclusive video interviews with DC.

By Dan Themig, Packers Plus Energy Services

A number of different justifications can be made for decisions on tool selection for open-hole multistage fracturing. More specifically, what type of packer provides reliable isolation and sufficient strength and durability to handle the high-pressure conditions required for multistage fracturing?

Figure 1: A study involving 24 wells in the Bakken formation in North Dakota compared the production of wells completed with swellable packers versus those completed using dual-element, hydraulic packers. This plot shows the relative locations of the wells in the study.

Comments – such as “they’re not great, but they’re good enough” – have been made regarding certain types of packers. Such comments indicate that the tools selected may not be well-suited for the application.

What is the cost of settling for “good enough”? This article presents a recent production study that begins to shed light on whether this is an acceptable compromise. In addition, studies have been completed regarding open-hole packers of various designs and builds to investigate whether they provide suitable isolation from an engineering standpoint (Rivenbark and Dickenson, 2011). A thorough understanding of these issues could prove important for decisions in field development.

Theoretical analyses have also been done on the importance of having annular isolation with sufficient pressure rating to effectively compartmentalize a horizontal well for multistage fracturing. However, the critical factor is how the isolation method performs in a well, or more importantly, in full field development, and what type of production results are achieved. Is there a difference?

Based on the following studies, it appears that the choice of isolation method can affect not only the efficacy of stimulation but also well production volumes.

Evaluating packer technologies

When determining which type of packer is appropriate for open-hole, multistage fracturing applications, many issues need to be considered. Simplicity alone may not warrant consideration when evaluating from an engineering standpoint. What is key is that isolation is consistently achieved, both during setting conditions and fracturing treatments.

The key factors that should be considered are discussed below.

Operation and installation

A key consideration when selecting packer type is operation and installation effectiveness. A dual-element, hydraulic-set, mechanical packer is relatively short (approximately 5 ft) with a reduced-diameter center section, allowing for installation in wells with high dogleg severity and, in some cases, even short-radius wells.

Additionally, the dual-element, hydraulic packer contains a sealing element at both ends, and the design of the element effectively isolates a much longer section than the element alone (approximately 4 ft). In this way, there are elements on both the high-pressure and low-pressure sides.

During high-pressure operation, forces from the high-pressure side will force-load into both elements and essentially provide a self-correcting and appropriate sealing force against the formation.

To set, dual-element, hydraulic packers require circulating a setting ball down to a circulation sub at the end of the system while simultaneously removing drilling mud and circulating the horizontal section to the completion fluid. Hydraulic pressure inside the system is then increased by pumping fluid from surface, and, at a specific pressure, the packers along the system will set.

In contrast, a swellable elastomer packer designed to efficiently handle fracturing pressures will be very long due to the length of elastomer required to attain high-pressure isolation (typically 10 ft to 20 ft). The diameter of the swellable elastomer will be the same along the entire packer. From an operational standpoint, long-sealing element packers can be difficult to install in wells with high dogleg severity. In addition, once activated, swellable elastomers are typically low-strength (approximately 40 durometer) and relatively soft. Friction coefficients for installing swellables can be fairly high.

Swellable elastomers also require a considerable amount of time from installation until they are fracture-ready. This can increase costs significantly in environments where rig costs are high, such as deepwater. Setting swellables requires circulating the horizontal section over to an appropriate fluid to make the elastomers swell.

In addition, field experience in lower bottomhole temperature environments shows that swell time may be highly inconsistent. In one test environment in a naturally fractured formation, the anticipated swell time for the swellables was three days. The operator set up the completion so that he could maintain the ability to circulate, thus verifying packer setting (swelling).

Due to the combination of fluid leak-off into the natural fractures and a limited bottomhole temperature, the operator was able to continue circulating for six weeks following installation of the swellables.

Thermal stability

The thermal stability of packer elements is another key consideration for successfully establishing mechanical diversion during fracturing operations. The importance of thermal stability was demonstrated by an operator who tested a series of open-hole packers under temperature-dynamic conditions. The test required the attainment of 10,000-psi pressure capability, as well as the ability to hold pressure during a cool-down from 300°F (simulating bottomhole temperature) to 120°F (simulating cool-down during fracture operations).

During the test, a phenomenon called “thermal shock effect” was observed in all swellables tested (three major suppliers). While all swellables, given enough length, were able to withstand 10,000 psi, when cool-down began, the elastomers experienced a thermal shock, which caused pressure failure in every case tested. When tested under identical conditions, the dual-element, hydraulic packer proved able to maintain 10,000-psi differential while cooling from 300°F to 120°F.

Prior to horizontal multistage fracturing, a considerable amount of literature established the suitability of swellables. At that time, knowledge of the thermal shock effect was known. One technical paper stated, “The contraction will lead to a drop in internal element pressure; ultimately, it will result in a physical shrinkage, and the pressure seal will be lost” (Evers et al., 2009). The paper indicated that the thermal coefficient of expansion and contraction for swelling elastomers is 10 times higher than it is for steel. In essence, without sufficient time to swell, isolation may be lost as the elastomer cools down with pressure differential.

Stress on formation

The amount of stress a packer puts on the formation should also be evaluated when determining the appropriate isolation device for open-hole multistage fracturing. Several technologies are available to provide mechanical isolation in open-hole wellbores.

A recent paper compared several of these technologies, including swellable, inflatable and hydraulic-set mechanical packers (Roundtree et al, 2009). The paper stated that an open-hole hydraulic-set mechanical packer will impart 6,000 psi of stress on the formation rock. Although it was determined that the hydraulic-set, mechanical packer imparted sufficiently high stress on the rock to cause failure of the rock, more effective mechanical-set hydraulic packers do not exhibit these types of stresses.

Verified by Houston’s Stress Engineering, a dual-element, hydraulic packer (the RockSEAL II) at fracture-treatment pressure imparts only 600 psi to 800 psi. Based on their analysis, this is believed to be the appropriate stress for nearly all formation types, both soft and hard rock.

Based on empirical evidence, including the ability to maintain a 10,000-psi differential rating during fracture breakdown operations, this author believes that dual-element, hydraulic packers are the only current industry tool that will provide high-pressure isolation in nearly all conditions. In addition, if water control for future applications or water flooding are required, a hydraulic-set packer with suitable elastomers has been the standard of the industry for more than 50 years.

Figure 2: In the 24-well study, the average cumulative production volume over 18 months from wells completed with dual-element, hydraulic packers consistently topped production from wells completed with swellable packers.

Production comparison study

This study involved 24 wells in close proximity in the Bakken formation in North Dakota. The wells were drilled and completed during the same time period and used similar fracturing programs. The primary dividing point for this data was that one operator exclusively used swellables while the other operator used dual-element, hydraulic packers. Both large-scale and side-by-side well comparisons were conducted. In addition, water production was studied for both types of isolation packers.

Figure 1 shows the study area, with swellables being used in one segment of the field by one operator and dual-element, hydraulic packers in the other segment of the field by a second operator. Figure 2 presents the first 18 months of cumulative production. There is a clear difference between recovery using the two different isolation technologies.

The wells completed with dual-element, hydraulic packers outperformed the wells completed with swellables by nearly 50% – 106,300 bbls versus 71,500 bbls – a difference of 35,000 bbls. Side-by-side well comparisons showed a similar 50% increase in recoveries for wells completed with dual-element, hydraulic versus swellable packers (data not shown).

Figure 3: Water production from wells completed with swellable packers was higher than from wells completed with dual-element, hydraulic packers in a study of 24 wells in North Dakota’s Bakken formation.

Next, a comparison was made regarding water production in these wells. The wells completed with swellable packers produced considerably more water than those completed with dual-element, hydraulic packers (Figure 3). The additional water could be due to multiple fracture treatments being placed in a single area. In other words, instead of initiating a new fracture, which would contribute to higher recovery, an interval that has already been stimulated is refractured.

This causes two problems: first, a loss of production from the area where isolation was not achieved; second, fracturing an interval twice, or even three times, can result in too much height growth, causing the fracture to extend into water-bearing intervals.

Key conclusions from the study are:

• Effective mechanical diversion is extremely important for open-hole multistage fracturing;

• Dual-element, hydraulic packers have a significant performance advantage over swellables during hydraulic fracturing operations;

• A suitably designed dual-element, hydraulic packer provides appropriate force on the rock and will not cause formation failure;

• The thermal shock effect may cause packer element failure of swellables during fracturing operations;

• Isolation failure during fracturing operations can cause excessive water production and ineffective stimulation resulting in reduced production;

• Dual-element, hydraulic packers are the most effective method of achieving mechanical diversion during fracturing operations.

Conclusions

A “good enough” choice of isolation technologies for field development using open-hole multistage fracturing can prove costly. In the production comparison study presented here, wells completed with dual-element, hydraulic packers exhibited a 50% increase in productivity over those completed with swellables. The thermal shock effect may have resulted in lost stages and overstimulation in some parts of the horizontal.

With the theoretical and empirical evidence presented in this article illustrating the benefits of dual-element, hydraulic packers, “good enough” may be a poor selection criterion.

RockSEAL is a registered trademark of Packers Plus Energy Services.

References

Evers, R., Young, D., Vargus, G. and Solhaug, K. 2009. Design Methodology for Swellable Elastomer Packers in Fracturing Operations. Paper OTC 20157 presented at the 2009 Offshore Technology Conference in Houston, Texas, 4-7 May 2009. 

Rivenbark, M. and Dickenson, B. 2011. New Openhole Technology Unlocks Unconventional Oil and Gas Reserves Worldwide. Paper SPE 147927 presented at the2011 SPE Asia Pacific Oil and Gas Conference and Exhibition in Jakarta, Indonesia, 20-22 September 2011.  

Roundtree, R., Eberhard, M. and Barree, R. 2009. Horizontal, Near-Wellbore Stress Effects on Fracture Initiation. Paper SPE 123589 presented at the 2009 SPE Rocky Mountain Petroleum Technology Conference in Denver, Colo., 14-16 April 2009.