Deepwater demands require upgrade in surface, downhole technologies alongside industry collaboration

By Joanne Liou, editorial coordinator

Deepwater drilling in the US Gulf of Mexico (GOM) is pushing limits with depths around 34,000 ft, more than 25,000 psi bottomhole pressure (BHP) and 250°F bottomhole temperature (BHT), and the numbers will only get higher with the next generation of deepwater rigs and equipment. Tomorrow’s rig will boast the capacity to reach 35,000- to 40,000-ft measured depth with more than 30,000-psi BHP and greater than 300°F BHT, Rohit Mathur, account manager of Baker Hughes, explained at the IADC International Deepwater Drilling Conference and Exhibition in Rio de Janeiro, on 17 April.

The increasing demands of deepwater drilling require upgrades in not only the rigs and equipment but also in communication and collaboration, Baker Hughes’ Rohit Mathur said at the IADC International Deepwater Drilling Conference and Exhibition in Rio de Janeiro on 17 April.

Presenting a service company’s approach, Mr Mathur explained the current challenges in the GOM, from hurricanes to high pressures, that are shaping expectations of the type of rigs that will be necessary and the equipment specifications that will be needed in light of formation issues and the wellbore itself. “The next-generation (derrick) will need to be rated to 2.5 to 3 million lbs, 2 million-lb traveling capacity, 2 million-lb active heave compensation, 30,000 ft or more of tubing racked back on rig floor itself and have the capability to drill at least to 40,000 ft drilling capacity on depth,” he said.

In the next five years, Mr Mathur expects deepwater rigs to have 12,000-ft storage of riser onboard and in the next 10 years, 15,000 ft. Cementing units will need 3,000 hp or more and be capable of high-pressure fracturing operations.

He also believes that wired drill pipe will become more prevalent in deepwater operations despite the higher costs. “There is a demand for higher data density, more real-time data in productive zones,” he said, noting that the limits of mud-pulse telemetry may be exceeded as we push wells depths to the 30,000- to 35,000-ft mark.

The additional uncertainties associated with deeper, sub-salt formations also create a need for better integration of wellbore programs utilizing real-time LWD, real-time drilling dynamics, seismic modeling and a 3D well plan model. “One picture gives a better, clearer understanding of what zones we’re trying to hit, how we’re hitting them, how we can exit out of that and basically improve the whole field development provided the better understanding,” Mr Mathur said.

Upgraded technologies also implicate a need for better communication and collaboration. “The communications workflow needs to be smoothened out,” he continued. “Everyone needs to know who to call, which would basically mean people at the rig site, at the office, team leaders talking to each other and keeping in the loop. We talk about technology, but we also need the piece of communication to do the work.”

Given the vast task ahead in deepwater, Mr Mathur believes that the industry is lacking a coordinated effort but notes that “there is definitely growing awareness among the industry.” Where there is an awareness of what needs to be done, individual companies are honed into their own projects and programs. “Everybody’s doing their own training program, but there’s not coordinated effort,” he said. “That’s what I’m calling for. There is a need to bring this big picture where everybody can talk the same lingo, the same language on what process, policies need to happen at the rig site, to prevent a disastrous situation from occurring.”

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Well depth extended in geothermal project using controlled pressure drilling

Figure 1: The Kirchweidach wells have the longest open-hole sections for geothermal wells, from 1,241 meters to 1,378 meters.

Underbalanced runs prevent mud losses and reservoir damage, allow well to hit main fault

By Essam Sammat, Stephen O’Shea, Gareth Innes, Weatherford UK; Julio Kemenyfy, Darko Piscevic, GEOenergie Bayern

Wells in the Kirchweidach geothermal project in Bavaria, Germany, and other offset wells in the area have faced problems such as severe mud losses and differential sticking in the reservoir formation. However, control pressure drilling (CPD) was successfully applied to address those challenges.

The project’s objective was to erect a power plant that would produce 6 to 8 MW of electricity and supply the local town and industries with district heating using thermal energy. Two wells were planned targeting natural fractures in the Malm formation (Jurassic carbonate), including one producer and one injector. This would allow more than 90% of the produced water to be returned to the reservoir, in time making the project sustainable.

The first geothermal well was drilled using CPD equipment in the reservoir section from the beginning. The underbalanced borehole pressure was achieved by pumping various rates of nitrogen and fresh water with polymers, which can significantly reduce nonproductive time and formation damage. For the second well, CPD equipment was used only after mud losses appeared.

The Malm formation is an underpressured aquifer that is often karstified, which at times resulted in severe or total fluid losses in the wells crossing it. In Kirchweidach, the top of Malm is at around 3,450 meters TVD, 400-meters thick and 130°C. As fluid losses during drilling are an indicator of success for the project, a procedure was implemented to allow drilling under these conditions to reach all targets while keeping the reservoir as clean as possible.

The Kirchweidach wells have the longest open-hole sections for geothermal wells, with GT 1 at 1,276 meters, GT 2 at 1,241 meters and GT 2a at 1,378 meters. They are also the only horizontal wells drilled in this formation. At the top of Malm, the separation between GT 1 and GT 2a is 1,600 meters. Figure 1 shows the typical well design, and Figure 2 shows the structural placement of the wells.

Controlled Pressure Drilling

Controlled pressure drilling uses a closed and pressured wellbore instead of drilling with the hole “open” to the atmosphere. A rotating control device (RCD) closes the well at surface, allowing for more precise control of the pressure profile. The RCD directs the flow of cuttings brought up by the aerated/nitrified fluid from the rig to the geothermal separator.

To do this, the flowline from wellhead to separator connects to a drilling spool below the RCD. This facility also provides the option of flowing cold water over the top of the well to stay within RCD rubber element temperature specifications if necessary.

The rubber seal unit rotates with and seals around the drill pipe and tool joint when drilling, making connections or tripping in or out of the hole.

The three main types of CPD methods are air drilling (AD), managed pressure drilling (MPD) and underbalanced drilling (UBD). AD is geared toward increasing the rate of penetration (ROP), MPD reduces rig non-performance time, and UBD minimizes reservoir damage and increases productivity.

Well GT 1 was drilled using two of these CPD methods as it varied temporarily from at-balance to underbalance conditions using nitrified fresh water, with the intention to avoid continuous influx to surface. Accordingly, the drilling method could justifiably be termed CPD, MPD or UBD. For this article, the four runs undertaken will be referred to as UBD Runs 1, 2, 3 and 4 even though the well was not strictly continuously in underbalance conditions.

Table 1: Well GT 1 was planned as a 3-B-4 under the IADC Well Classification System for Underbalanced Operations and Managed Pressure Drilling. The well’s open-hole section was drilled in two phases using a total of four UBD runs.

Planning

Well Classification

IADC’s well classification system for underbalanced operations and managed pressure drilling (MPD) describes a well using a three-digit code based on overall risk, application category and fluid system.

Based on this system, GT 1 was planned as 3-B-4:

• Overall risk was Level 3: geothermal and non-hydrocarbon production. Maximum shut-in pressures less than UBD equipment operating pressure rating. Catastrophic failure has immediate serious consequences.

• Application category is Category B: underbalanced operations. Performing operations with returns to surface using an equivalent mud weight that is maintained below the open-hole pore pressure.

• Fluid system is 4 (gasified liquid): fluid medium with a gas entrained in a liquid phase.

Table 2: Minimum liquid flow velocity was an important input parameter during pre-job and rig-site modeling of multiphase flow using a simulator. It determines the cutting-carrying capacities. Table 2 shows the values for minimum hole-cleaning capacities for water-based mud based on experience.

Objectives

The objective of GT 1 was to drill the 9 ½-in. open hole to TD using CPD methods with the following criteria:

• Drill the open hole with a two-phase water and nitrified fluid to maintain CPD conditions in the open hole, avoiding reservoir damage;

• Avoid drilling problems such as mud losses, differential sticking and potential kicks by proper fluid control and measurement; and

• Allow potentially faster ROP and lower total drilling days. This was a secondary objective compared with the primary objective of avoiding losses.

By successfully using CPD methods, the following results may also be possible:

• Drill to TD with full returns, allowing collection of geological information;

• Reservoir/production evaluation and characterization while drilling; and

• Gather data for drilling performance optimization and future well planning.

Modeling

Pre-job and rig-site modeling of multiphase flow was done using an advanced simulator to determine the required underbalanced drilling conditions. These include the following input parameters:

1. Gas-to-liquid ratios are evaluated and selected to reduce the hydrostatic pressure within the annulus to achieve the desired bottomhole circulating pressure.

2. Minimum liquid flow velocities, which determine the cutting-carrying/hole-cleaning capacities. By experience, the values for minimum hole-cleaning capacities for water-based mud are:

• Well trajectory: minimum required velocity;

• Horizontal: 55 meters/min; and

• Vertical: 45 meters/min;

3. The mud motor equivalent liquid volume (ELV) is taken into consideration. This value cannot be exceeded.

4. The gas volume fraction (GVF) in the drill pipe can affect downhole tool performance.

Figure 2 shows the structural placement of the GT 1, GT 2 and GT 2a wells in the Kirchweidach Geothermal Project. GT 2a had the most challenging well path as it targets a fault to the north and has inclinations of up to 97° for a long section. CPD equipment was therefore rigged up before the expected losses zone rather than after the losses appeared in GT 2a.

Modeling was performed using data provided by GEOenergie Bayern and known physical constants. To function, Neotec requires a number of input values, including the specific gravity of the intended drilling fluid, composition of the injected gas, borehole trajectory and annular design. Additionally, drill string design, including tubular profiles and operating limits (pressure drop and max motor ELV), are of interest as points of increased annular friction or pressure drop, which can affect downhole fluid velocity.

Estimations are substituted. Initial indications were that target formation pressure was 351 bar (5,089 psi) and formation temperature was 145°C (293°F). Reservoir pressure was thought to be 383 bar (5,555 psi) at TD. Offset wells reported partial to total loss scenarios when drilling with 1.02 to 1.05 sg (8.4 to 8.7 ppg).

A primary requirement of the CPD operation was to reduce annular friction pressure, which is responsible for increases in the bottomhole pressure and the potential for fluid loss. A solution was to establish a high nitrogen injection rate with a moderate fluid injection rate. This also increases the fluid velocity, which aids hole cleaning. When working in a very narrow pressure window, the case where the well is not producing at the casing shoe is considered the worst-case scenario.

Fluid injection rates were designed to lie within the capabilities of the equipment available while not exceeding reservoir pressure draw-down of 10%. Initial modeling was conducted with rates varying from nitrogen at 18 cu meters/min to 28 cu meters/min and fluid injection at 2,000 lpm to 2,600 lpm.

An operation envelope was created that identified an optimal injection rate of 22.6 cu meters/min of nitrogen and 2,400 lpm of drilling fluid with a density of 1.02 sg. This produced a reservoir draw-down of 4 bar (58 psi) while remaining within operating limits of less than 18% GVF (5%) and motor ELV limits.

However, these injection rates provide hole-cleaning velocities of 41 meters/min in the vertical section. Experience has shown that under these conditions, adequate hole cleaning can be achieved through the scheduled pumping of high-viscosity pills, reciprocating the drill string prior to connections and low ROPs. On the other hand, should the reservoir flow, vertical and horizontal fluid velocity would exceed their minimum thresholds, and hole cleaning would be vastly improved.

While concentric casing and parasitic string injection methods were known to be highly effective nitrogen injection methods, drill pipe injection was chosen as it was shown to be adequate.

Nitrogen

There are two methods for getting the required supply of nitrogen on the rig site.

Cryogenic nitrogen is widely used in drilling operations as it is transported to the well site as a liquid, and the boiling point of liquid nitrogen is -196.1°C (-321°F) at atmospheric pressure. Cryogenic tanks are necessary for transportation and storage on location.

Because the nitrogen is pumped as a liquid and the conversion from liquid volume to gas volume at standard conditions is well characterized, it is straightforward to accurately measure and control the nitrogen delivery rate. This also comes with a guaranteed nitrogen purity of 99%, which vastly reduces corrosion effects on equipment.

Membrane nitrogen involves stripping nitrogen molecules from the local atmosphere. This system has different equipment requirements to the cryogenic method, but once the sourced nitrogen is in the standpipe, it provides the exact same function.

Regardless of the nitrogen source, it eliminates the possibility of downhole fires. Pure cryogenic nitrogen also prevents downhole corrosion due to the purity level. Membrane-generated nitrogen contains some oxygen, and downhole corrosion remains a concern. Awareness of corrosion effects is crucial to safe operations and equipment maintenance. Other factors need to be considered before it is decided to use cryogenic or membrane nitrogen, such as cost, availability, site layout and available space, diesel consumption, and noise control.

Based on the above criteria, the plan was to drill GT 1 using cryogenic nitrogen.

Development

Equipment Selection

The CPD geothermal package was designed to have an efficient and minimal on-site footprint. The Model 9000 RCD was perfectly suited for the well conditions projected with 34 bar (500 psi) operating pressure rating, and they close the annulus to the rig floor. RCDs are not well control equipment, and no CPD equipment was labeled as such.

An adapter and two drilling spools were installed between the top of the blowout preventer and the base of the RCD. One of the drilling spools had outlets to connect to the 8-in. flow line and the injection of cold water across the top of the well. The purpose was to ensure heated fluids did not decrease the expected life span of the rubber sealing element.

Between the wellhead and the geothermal separator, a globe valve was installed to regulate flow from the well to stem intermittent slugging from the annulus that was expected to occur. In the top-hole section of the annulus, nitrogen becomes free to rapidly expand due to a decrease in hydrostatic pressure, resulting in slugging at surface. The globe valve was a simplified and recognized method of manually applying surface back pressure to control the release of this fluid.

An 8-in. flow line and a geothermal separator with adjustable frame to match the shaker tank height complete the return flow system. The geothermal separator is where the nitrified drilling fluid is first exposed to open atmosphere and was designed to effectively allow the separation of nitrogen from the drilling fluid. This equipment employs the principle of centrifugal force for liquid-gas separation as in cyclone equipment. The nitrogen-free liquid then goes down to the shale shaker and back into the pits. The geothermal separator has 8-in. inlet and outlet flow lines, and the inside of the separator is lined to reduce erosion.

Data acquisition equipment on-site recorded flow-out temperature and pressure. Also monitored were nitrogen injection pressure, temperature and flow rate. Nitrogen pump pressure must be high enough to entrain nitrogen in the stand pipe. All data was available and transmitted via the rig-site WITS network.

Float subs were inserted to the top of the drill string to prevent the upward migration of nitrogen when the rig pumps were turned off. This increased safety, reduced wasted nitrogen and reduced time spent bleeding the drill string when making a connection.

Drilling Procedures

A number of drilling procedures were drawn up aimed at increasing the preparedness of the rig crew for events that could occur and aid steps to reach TD as quickly as possible without taking shortcuts. These issues had to be addressed before operations commenced as many personnel were being exposed to closed-loop and hydrostatic balance manipulation methods for the first time. This was a critical step toward ensuring personnel and equipment safety on the rig site and mitigating drilling hazards.

Drilling with nitrified fluid creates scenarios that conventional drilling operators may not be familiar with. Therefore, procedures were translated into German and circulated to the relevant people.

In addition to normal UBD operation procedures, rig crew were presented with the information that would allow them to react to equipment failures, well control and ESD events in which the presence of nitrogen would be a factor to consider. Another critical factor to account for was the communication between rig floor and the nitrogen injection crew. Standard rules for radio communication and reporting were established.

Operations

The GT 1 open-hole section was drilled in two phases using four UBD runs. Initially, UBD Runs 1 and 2 were drilled from the 10 ¾-in. liner shoe at 3,664-meters to 4,503-meters MD. A subsequent acid job and well test proved unsatisfactory, so the UBD separation and nitrogen injection packages were rigged up again. UBD Runs 3 and 4 were drilled from 4,505-meters MD to 4,937-meters MD.

UBD Run 1

This run was conducted from 18-25 February 2011. A 3-meter rat hole was drilled beyond the 10 ¾-in. liner. The run initially started well with full returns and a low

Figure 3: A high nitrogen injection rate with a moderate fluid injection rate was established to reduce annular friction pressure, which is responsible for increases in the bottomhole pressure and the potential for fluid loss. An operational envelope was established at the 10 ¾-in. liner shoe that identified an optimal injection rate of 22.6 standard cu meters/min (800 standard cu ft/min) of nitrogen and 2,400 lpm of drilling fluid with a density of 1.02 sg.

nitrogen rate, which kept the operation slightly overbalanced. Nitrogen injection rates were gradually increased to 14 cu meters/min and held steady at this rate as the UBD system was effective in lowering the equivalent circulating density.

Although this is below the initial model predictions, this left room to increase if desired. On 23 February, it was found that LWD transmissions were very noisy, and signals were not received with a nitrogen flow rate over 12 cu meters/min. A compromise was made to maintain flow rates to ensure adequate data transmission from the tool to the surface. This effectively increased the ECD and ESD, and the system was not truly underbalanced at all times, but it enabled the rig to continue drilling in the given circumstances.

Foaming issues became a problem on 19 February due to the reaction of the drilling fluid polymer (xantin gum) with nitrogen. The initial solution of adding a defoaming agent proved to temporarily solve the issue, but the problem persisted and the system became unmanageable.

The decision was taken to completely replace the drilling fluid in the pits with fresh water without any polymer. Although this was not ideal, returns were recorded on surface, and it helped decrease the daily costs for drilling fluid.

On 25 February, with ROP consistently low at 1 meter/hr, the decision was made to pull out of hole and change the bit. At this point, the bit had spent 96 hrs on bottom. An average instantaneous ROP of 11.6 meters/hr across for this run was recorded, which was decreased by the time spent drilling with the greatly deteriorated bit.

UBD Run 2

A second UBD run was started with a new bottomhole assembly run in hole on 26 February. On this occasion, LWD signal transmission was greatly improved at nitrogen injection rates of 16 cu meters/min. LWD data transmission was lost on 27 February at a depth of 4,219-meters MD. Neotec calculated ECD and bottomhole pressure in line with LWD output prior to end of transmission. The decision was taken to continue to drill ahead without MWD directional guidance.

From here on, knowledge of bottomhole conditions was solely based on the calculated model, which until this point had tracked MWD readings with great satisfaction. For this run, increased emphasis was placed on pit volume tracking. It was in this bottomhole section that significant formation fluid gains were taken while drilling UBD as the reservoir was induced to flow to surface.

Increased torque was experienced while backreaming before connections from a depth of 4,320-meters MD. TD was called at 4,503-meters MD on 2 March 2011. Due to the lack of MWD guidance, the planned hole trajectory was not properly followed. Cave systems and pronounced fractures along the well path explain periods of diverse drilling parameters and pit volume changes.

Traditionally, cave systems add complexity to UBD jobs as they can cause both high fluid gains and losses at surface. These may have been a location of temporary cuttings storage. On flowing the reservoir when pulling out of hole and during the wiper trip, this may have been a source of cutting re-injection back into the annulus.

An average instantaneous ROP of 8.5 meters/hr was recorded for this run.

UBD Run 3

UBD Run 3 started after the stimulating and test work done in the well gave unsatisfactory results, and the decision was made to extend the well to try to reach the main fault. This time CPD was paramount to get returns while circulating as the losses were above 140 cu meters/hr, and the available supply of water was 60 cu meters/hr.

Early attempts to initiate full conventional circulation failed, with the rate of fluid losses to formation too high to maintain the required surface pit volume to continue drilling. Drilling eventually commenced with the sourcing of additional water supply.

On 17 April, annular injection started with a two-phase fluid of water and nitrogen being pumped between the 20-in. surface casing and 13 3/8-in. concentric casing. As this operation progressed, nitrogen injection was gradually increased as drilling fluid injection was decreased. This continued until it was possible to just pump nitrogen in the annular cavity.

The rig pumps were then realigned to start pumping drilling fluid down the drill string, and rotary drilling commenced. This dual-injection method worked initially with optimal rates of 2,000 lpm of drilling fluid and 10 cu meters/min of nitrogen.

A decision was made to investigate the effect of increasing annular nitrogen injection from 10 cu meters/min to 20 cu meters/min. This proved less optimal, and the nitrogen rate was returned to 10 cu meters/min. However, this had the effect of essentially super-charging the annular cavity with nitrogen. As this nitrogen rounded the concentric casing perforations, high-pressure slugging resulted in the well blowing itself dry. Concentric casing injection was halted, and nitrogen was realigned to pump down the drill string.

The presence of this concentric casing, however, was beneficial for the fact that the annular pressure drop was decreased, making it easier to lift cuttings out of the hole.

At 4,540-meters MD, a short trip was performed, and the string was pulled back to 3,555-meters MD. Annular nitrogen injection was halted, and the operation resumed with just drill pipe injection. Injection rates of 2,000 lpm drilling fluid and 10 cu meters/min nitrogen remained optimal values for maintaining adequate fluid return rates to continue drilling. Return rates were typically 50% of volume pumped, which was typically calculated to be a loss of 60 cu meters/hr. The high loss rate is attributed to the acidizing job that was performed after UBD Run 2. The increase in size of fissures and fractures led to increased permeability. A high proportion of fluid pumped from surface was lost to the formation, with nitrogen moving to the high side of the horizontal section, where it too was mostly lost to formation. It is believed some volume of nitrogen did return to surface, but this was very minor with respect to the volume injected. However, the presence of the nitrogen was responsible for decreasing the hydrostatic head sufficiently that some formation fluid influx was induced in the open-hole section above acidized zone.

Further, nitrogen prevented sticking at tight spots along the well path that developed in the later stages of UBD Run 2.

Figure 4: The initial planned well profile for GT 1 was changed when TD was extended. The scope was originally to drill the well underbalanced through the Malm reservoir carbonates to 4,720-meters MD to evaluate and exploit the geothermal properties of the reservoir. After four underbalanced drilling runs, TD was called at 4,937-meters MD. By extending the well depth, objectives were achieved. This was enabled by the use of controlled pressure drilling techniques.

At 4,670-meters MD, drill pipe injection rates were increased to 2,500 lpm and 15 cu meters/min. A bit trip was called at 4,726-meters MD. The average instantaneous ROP for UBD Run 3 was 15.3 meters/hr.

UBD Run 4

UBD Run 4 drilling commenced with fluid and nitrogen injection rates varying from 2,300 lpm to 2,500 lpm and 15 to 20 cu meters/min respectively. This run was rather uneventful compared with UBD Run 3. Average ROP for the section was 9.6 meters/hr. Improved returns were viewed, and this is likely due to the eventual plugging of fractures and fissures, as well as formation of skin on borehole walls. A number of pills were pumped after TD, and this helped clean the hole of a large quantity of cuttings.

The drill string became stuck while pulling out of hole, and the re-introduction of nitrogen was found to aid the recovery. Reduction of differential sticking is a long-recognized benefit of UBD and previous wells in this locality have all run into pipe stick problems at shallower depths.

The temperature of returns at surface was noticeably below that experience on UBD Runs 1 and 2. This is a strong indicator that water was being produced from above the acidized zone at shallower depths. LWD data is the best source for bottomhole temperature comparisons. TD was called at 4,937-meters MD (3,793.3-meters TVD) at 17:35 on 27 April 2011. An additional concern with the rig was the drill string weight approaching the maximum pulling capability of the rig.

Lessons Learned

Problems stemmed from the MWD/LWD failure in UBD Run 2 and the decision to drill on.  Several points were noted regarding the tool build, and MWD/LWD tool performance at high pump rates for UBD Runs 3 and 4 was greatly improved. Electromagnetic measurement-while-drilling tools were cost-prohibitive but would have not suffered annular fluid composition-related interference. In the end, improved tool design was sufficient, and perfect detection was recorded at the elevated pump rates. Additionally, the mud motor was changed from 6 5/8 in. for UBD Runs 1 and 2 to 8 in. for UBD Runs 3 and 4. This also enabled a greater motor throughput, raising the ELV.

While concentric casing injection was not a success in this case, its presence in the annulus for UBD Runs 3 and 4   indicated further analysis needs to be done for the concentric drilling method before applying it in the future.

Without accurate flow detection rigged up on the flow line, watching pit volume gains and losses is crucial to understanding the downhole performance of the system.

Foaming was not initially accounted for and provided some adverse drilling conditions. Preemptive and aggressive defoaming is essential for nitrified drilling fluid operations. In a very active system this is not always possible, but it is highly recommend.

Using concentric casing carries a risk, which may not be worth the investment in rig modification as the drill pipe injection method used on GT 1 has proven successful. It is strongly advised to employ this method on future UBD wells in this region.

The application of multiple float subs and NRV’s greatly reduced time spent bleeding nitrogen from the drill string once the rig pumps were shut down. The GT 1 well introduced UBD technology to the rig crew and other service companies, which inevitably caused some confusion and problems, especially when adding the language barrier between the rig crew and the UBD crew. This is expected to greatly improve in future operations where the rig crew has a better understanding of the equipment and techniques used during UBD operations.

The knowledge that the UBD crew has acquired of the rig and the location will also aid in improving future operations.

Conclusion

The scope of this operation was to successfully drill the GT 1 well underbalanced through the Malm reservoir carbonates to a depth of 4,720-meters MD to evaluate and exploit the geothermal properties of the reservoir. After four UBD runs, TD was called at 4,937-meters MD. The expected test results were not achieved on the first attempt, but after extending the well to its final TD of 4,937 meters, the well objectives were accomplished.

The use of CPD was a key factor for the efficient drilling of the extension.

UBD techniques enabled GT 1 to achieve a greater depth than any known well previously drilled in this locality. Additionally, the ability to achieve 100% returns is a vast improvement over conventional techniques previously applied in the area. Total loss situations were avoided on UBD Runs 1 and 2.

Ultimately, UBD permitted GT 1 to be drilled to a point where well testing could be possible with reduced formation damage due to the invasion of drilling fluid solids.

While the original well path was changed, drilling the longest open-hole section in the Malm reservoir allowed it to hit all the planned targets, providing significant information about the target reservoir. Moreover, extending the well TD to 4,937-meters MD in the Malm reservoir allowed a significant achievement by hitting the main fault in the area at +/- 4,900-meters MD. Achieving this objective will greatly aid future drilling in the region as well.

All of this would have not been possible without the aid of nitrified drilling fluid mitigating drilling hazards and lowering the annular hydrostatic pressure head.

The injection of nitrogen into an annular space created with a concentric casing string needs to be carefully planned and considered in the well design, otherwise it will lead to problems with the surface equipment due to irregular underbalanced conditions.

The use of annular pressure and temperature sensors can greatly assist in the determination of the rate of nitrogen to be pumped during drilling and can show influx/loss zones.

Although CPD was not used in the GT 2 and GT 2a wells, it was ready to be deployed and was considered as the technical solution to continue drilling if severe losses would have appeared. It is recommended to include early in the planning stages of the well design in geothermal projects in the area the use of CPD as an option to allow the reaching the well objectives in case total losses appear.

This article is based on SPE/IADC 156895, “Successful Controlled Pressure Drilling Application in a Geothermal Field,” 2012 SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, Milan, Italy, 20–21 March 2012.

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Refining the grip on nature’s fine grains

Complementary tools, approaches enhance tried-and-true sand control methods

Using fiber-optic technology, Baker Hughes has developed a real-time compaction monitoring system to monitor deformations of the well. The system provides real-time data and can monitor downhole conditions to detect any issues before they become a problem.

By Joanne Liou, editorial coordinator

Drawing on proven methods and technologies, the latest developments in the realm of sand control strategically capitalize on and enhance what is known to work. The challenge to control unconsolidated sand in the reservoir is met with a portfolio of evolving solutions that are producing better, faster and cheaper results. Mindful of risks and costs, the industry cautiously approaches sand control, managing complexity while reducing nonproductive time (NPT).

“The current thinking in deepwater is selecting the cased-hole completion technique and the processes that not only provides the best, fastest completions but also one that provides the least amount of risks because the daily costs of operating in deepwater for some of these rigs range from $500,000 to a million dollars per day offshore,” Bryan Stamm, technology manager of Schlumberger sand management services, said. “It’s not often that the new technologies are actually the game-changers, but it’s properly managing the packaging of the existing technologies.”

A recurring approach shared across the industry is to evaluate the utilization and application of existing technologies, then combine them with complementary elements and tried-and-true methods to produce even better results. Operators are asking service companies to provide methods that not only control sand production but also maximize productivity and increase recovery.

“Our customers are asking us to look at lower completions from a productivity perspective, not just as widgets,” Suzanne Stewart, Baker Hughes’ product line director for sand control and lower completions, explained. “Our philosophy is to look at the payzone and provide direct connections and enhance when we can in order to maximize the conductivity and to optimize production. That way, we are offering solutions and applications, not just providing widgets.”

The market and need for sand control is omnipresent from the North Sea to West Africa to onshore North America, and it continues to grow as trends point to developing significant fields. In this article, sand control experts from Schlumberger, Baker Hughes and Weatherford International share their approaches and recent developments.

M-I SWACO’s BREAKDOWN HD breaker system helps remove some of the more difficult polymer components of the filter cake.

Schlumberger

Proper evaluation and management of sand control methods have led to some of Schlumberger’s latest developments for open-hole and cased-hole completions. Offshore, particularly in deepwater wells, standalone screens or gravel packs are typically used in open hole, while frac-pack treatments are the most common cased-hole sandface completions technique. In both open-hole and cased-hole environments, how to effectively execute sand control with high efficiency and low NPT is the ultimate goal. With multizone applications, the goal is to effectively balance the reward of installation efficiency with the risk of NPT.

An area that has seen development in new technology is wellbore displacement and cleanup. “The chemistries, hydraulics and tools have always been available, but the combination of the three is seldom looked at as a complete system,” Mr Stamm said.

In proper wellbore cleanup, cleanliness is not intuitive to the drilling engineer, but it is of paramount importance to a completion engineer for both making sure the formation is not damaged, as well as making sure debris is removed from the wellbore. Debris could cause NPT associated with completion hardware.

M-I SWACO’s WELL PATROLLER and WELL SCAVENGER tools have been effective in removing debris in cased-hole completions and illustrate well cleanliness at surface. The former acts as a downhole filter during the displacement operation, removing any residual debris and validating on surface how well the displacement performed. The latter is a vacuum debris removal tool that provides reverse circulation at the end of the workstring to enhance debris removal, especially around sensitive areas or equipment, such as open perforations, formation isolation valves or temporary plugs. Captured debris is recovered at surface.

M-I SWACO’s WELL SCAVENGER is a vacuum debris removal tool that provides reverse circulation at the end of the workstring.

Sand control is part of the bigger picture, and drilling engineers are as important to the productivity of the well as engineers responsible for the completion design. “The highest value that we’ve seen is when there is an integrated team working for a common goal, not just individual objectives, such as ‘let’s just drill the well without any regard for completion,’ or ‘let’s complete the well without any regard for how it was drilled,’” Mr Stamm said.

In open-hole completions, breaker technology is a key aspect of managing the transition from the drilling phase through the completion phase and into the production phase. “But the filter cake treatment goes in combination with the fluid with which you drill in the first place,” Charles Svoboda, director of wellbore productivity, business development at M-I SWACO, a Schlumberger company, explained. “The breaker technology and the reservoir drill-in fluids have to be specifically designed together with the common objective of successfully drilling the well, completing it and then successfully producing from the well.”

The WELL PATROLLER tool acts as a downhole filter during the displacement operation, removing residual debris and validating well cleanliness.

In a 2011 case study offshore the east coast of Trinidad, the company’s BREAKDOWN HD breaker system enabled filter cake removal in a high-permeability open-hole gravel pack (OHGP) completion. The idea was to remove the filter cake in a gentle manner and not be too aggressive by compromising the filter cake integrity before the completion process was finished. The system allows users to get to higher densities and work in divalent chemistry – a calcium-based brine, Mr Svoboda explained. “The composition of BREAKDOWN HD helps us remove some of the more difficult polymer components of the filter cake that are sometimes used.”

Starch polymers, for example, break down easily with an enzyme treatment, but other fluid loss control and viscosifying polymers are more troublesome.

In the Serrette project in Trinidad, the wells had open-hole production intervals varying from 150 ft to 500 ft and contained high-permeability rock ranging from 1 to 3.5 Darcy. The reservoir drill-in fluid was engineered to limit fluid invasion and formation damage; however, there were indications of a high probability of severe production-restricting screen and gravel-pack plugging, making the placement of the filter cake removal treatment necessary during the placement of the OHGP.

To minimize interaction between filter-cake removal chemicals and the OHGP fluid, the breaker system was implemented to minimize interaction with the divalent brine system, retain adequate breaking power to remove the filter cake and maximize productivity. The final mixing and pumping process proceeded without issues or NPT.

“It’s an extension to where we’ve been,” Mr Svoboda said. “We’re now able to work in higher densities. We’re able to remove filter cakes that before hadn’t been removed by previous technologies.”

Baker Hughes’ GeoFORM Shaped Memory Polymer Sand Control System is engineered to potentially replace gravel packs in open-hole completions. Field trials are being conducted in Europe, offshore US and Southeast Asia.

Baker Hughes

Fiber-optic technology is no stranger to the industry, but its use for well and reservoir surveillance has evolved in the past decade. Baker Hughes and a major operator have collaborated to develop a technology to monitor the deformation of well tubulars and casing, which has expanded to monitoring sand screens.

The real-time compaction monitoring system enables the monitoring of the compaction-related deformations of the well. “Multiple fiber-optics string sensors give operators the ability to gain real-time information, allowing them to make changes,” Ms Stewart said. “The biggest benefit is that the system can monitor downhole conditions and then adjust to rectify a problem before it becomes a failure.”

The operator deployed the system for the first time with a downhole fiber-optic wet connect in the Gulf of Mexico (GOM) in November 2011. The system was applied to a cased-hole frac pack and was run on a 3 1/2-in. fiber-optic screen, inside 7 5/8-in. casing. Because the application was developed with a downhole fiber-optic wet connect, “we could run the upper completion and connect, so the fibers meet downhole,” Ms Stewart explained.

The fiber-optics string engages sensors at the sand face, which allows operators to continuously monitor the reservoir with fiber optics in real time. The technology uses Bragg gratings, which is a short segment on optical fiber that reflects particular wavelengths of light and transmits all others, she continued.

Baker Hughes introduced the industry’s first downhole fiber-optic wet connect in November 2011. The system is able to run the upper completion and connect, allowing the fibers to meet downhole.

“Each grating is essentially a strain gauge, and when strain is applied to the sensing fiber, the fiber is helically wrapped around the completion to be monitored, such as casing or sand screen, and the individual gratings in the fiber stretch or contract. This strain causes a shift in the wavelength of light reflected and produces strain measurements along the length of the fiber containing the Bragg gratings.”

Bragg gratings can offer an advantage over traditional electronic gauges in harsh environments because it can withstand vibration and heat, making it more reliable.

One of the newest sand control systems, GeoFORM, is based on shape memory polymer (SMP) technology. It has been engineered to potentially replace gravel packs in open-hole completions.

SMPs, introduced by Baker Hughes in 2011, resemble the material used in automobile bumpers. If there is a dent in the bumper, the repair usually involves applying heat to the area to make the dent pop out to its original form.

“SMPs have the ability to effectively remember the shape in which they were originally formed,” Ms Stewart explained. “We take the SMP, compact it to a smaller size, and then we effectively freeze it in that condition and run it in hole and allow it to go back to its original shape.” A pipe with an SMP is run in the open hole, where it can regain its original size and effectively fill the annulus. SMPs replicate a filtration system like a gravel pack without having to pump gravel.

Baker Hughes has undertaken seven SMP field trials to date in areas including Europe, offshore US and Southeast Asia, Ms Stewart said.

Weatherford’s SandAid treatment uses zeta potential altering chemistry to create an ionic attraction between particles and prevents them from migrating while allowing for adaptation to changes in formation stresses.

Weatherford

Conceiving the downhole production enhancement business unit, Weatherford combined chemical sand control with its water conformance technology in March. “Sand production and water production go hand in hand,” Ron van Petegem, product line director of downhole production enhancement for Weatherford, said. “There are many reservoirs out there that really don’t produce any sand. The rock may have even failed already, but when water production breaks through the capillary, pressures change. You may lose other cementation from clays and then comes the sand.”

Weatherford’s new approach looks at sand and water performances in tandem. Although the two are not necessarily complementary, they also are not mutually exclusive.

The magnified views illustrate untreated (top) and treated (bottom) sand grains/fines. When SandAid is pumped into the reservoir, the positively charged chemistry is attracted to the negatively charged sand, which leads to SandAid adsorbing the particle. The solution is formulated so that only a certain amount is adsorbed by the rock.

SandAid, originally field-tested in Romania and introduced to the market in June 2009 in the GOM, is one of Weatherford’s latest technologies and is still evolving in its makeup and application. The treatment incorporates Weatherford’s patented zeta potential altering chemistry, which in itself is not new to industry, but to modify the zeta potential for the purpose of sand control and increasing the maximum sand free rate is. The modification creates an ionic attraction between particles and prevents these particles from migrating while allowing for adaptation to changes in formation stresses. “Sandstone is anionic, negatively charged, and SandAid is mostly catanionic, so when SandAid is pumped into the reservoir, the positively charged SandAid and the negatively charged sand are attracted to each other, and SandAid adsorbs to the partile,” Mr van Petegem said.

The technology is typically deployed by bullheading it down the production tubing or coiled tubing; many operators prefer to bullhead the treatment down the production tubing because of the ease of placement, Mr van Petegem said. The typical treatment consists of a brine pre-flush, followed by the SandAid treatment and a brine post-flush. “We mix on the fly, and it’s an extremely simple process,” he explained. “It also means that in almost all cases, the fluids that we pump into the well are Newtonian, and as such rate diversion becomes simple and reliable, treatments are typically pumped at matrix rates just under frac pressure.”

Part of rate diversion implies that higher-permeability zones will receive more treatment than lower-permeability ones. It is essential that the chemicals do not over-treat part of the matrix, and more SandAid solution applied does not mean a thicker coating but translate into a deeper treatment, according to Weatherford. The philosophy of the design takes into consideration the minimum amount of treatment needed for lowest-permeability of the target zone. “That’s one of the key reasons for our success,” Mr van Petegem said. “Thus, during a normal treatment, the high-permeability rock will receive a deeper treatment than the low-permeability rock.”

SandAid chemistry is formulated so that only a certain amount is adsorbed to the rock.

Weatherford has applied the technology to more than 200 zones worldwide offshore and on land. In one of its first applications in the GOM, the company teamed up with an independent operator in mid-2009, and through June 2011, the treated GOM well produced at up to three times its previous maximum sand-free rate. Prior to the treatment when the well’s performance initially declined, a number of sand control options were considered. A workover with gravel-pack or frac-pack installation was deemed too costly and not fit to the existing completion configuration. SandAid technology was selected because the treatment could be mixed with seawater and bullheaded down the production tubing and because it would not reduce permeability.

Within 24 hours of application, the well was put on production, and as of April, was still producing sand free.

The chemistry of Weatherford’s SandAid technology is based on modifying the zeta potential of anionic particles. When formation stresses change because of reservoir depletion, its chemistry adapts to the changing conditions and re-agglomerates.

“Today we have a good, reasonably well-defined operating envelope,” Mr van Petegem stated, “but as we do more jobs, we continue to learn and expand our operating envelope.”

Taking a preemptive approach to sand control, the deployment of the technology is being rerouted. Weatherford is pursuing a concept called rock strength conservation, where sand control technologies are being applied to prevent failure instead of waiting for the rock to fail.

Working with a major operator and through internal testing, indications are that by applying the SandAid technology prior to water breakthrough, deeper reservoir depletion may be possible without sand production. “Essentially all sand control methods that we have today are reactive,” Mr van Petegem stated. “We may choose to install sand control systems proactively, but in essence, they do not really start operating until after the rock fails and sand becomes mobile.”

The proactive approach is a departure from the conventional sand control philosophy and would attempt to conserve and possibly prevent sand production in the first place, Weatherford believes, making it impervious to the change that is typically caused when water production starts.

Weatherford plans to do field trials for this reservoir conservation concept by mid- to end-2012 and has seen interest from operators in West Africa and the GOM.

In a separate development, Weatherford is working with operators to pump the SandAid chemistry from a floating, production, storage and offloading (FPSO) vessel through a flowline back into the well. “The considerations there are the cleanliness of the flowline itself because flowlines build up debris,” Mr van Petegem said. Weatherford is working with an operator to find the best way to clean the flowlines from the FPSO down to the well. “This could potentially allow failed deepwater wells without an intervention vessel do a sand control treatment remotely through flowline,” he added.

Conclusion

Methods of bringing unconsolidated formation sand under control are not confined to the completion phase but also affect the drilling and production phases. The industry’s approach to sand control and traditional methods are evolving to maximize proven technologies to produce the most desirable and profitable results.

“Baker Hughes does not have an allegiance to any one particular technology,” Ms Stewart stated, “which allows us to truly evaluate the payzone and to provide the best solution.”

WELL PATROLLER, WELL SCAVENGER and BREAKDOWN HD are marks of Schlumberger. GeoFORM is a trademark of Baker Hughes. SandAid is a trademark of Weatherford.

View the original article here

Baker Hughes Announces First Quarter Results

HOUSTON, April 24, 2012 /PRNewswire/ -- Baker Hughes Incorporated (NYSE: BHI) announced today net income for the first quarter 2012 of $379 million, or $0.86 per diluted share.  This compares to $0.87 per diluted share for the first quarter 2011, and to adjusted net income (a non-GAAP measure) of $1.22 per diluted share and net income of $0.72 per diluted share for the fourth quarter 2011.  Please see Table 1 for a reconciliation of GAAP to non-GAAP financial measures.

Revenue for the first quarter 2012 was $5.36 billion, up 18% compared to $4.53 billion for the first quarter 2011 and down 1% compared to $5.39 billion for the fourth quarter 2011.

"Our international business performed very well, relative to the typical seasonal declines we see in the first quarter.  In particular, the performance of the Europe/Africa/Russia Caspian segment was excellent, driven by strong results across Africa where we provided drilling and evaluation services on multiple high-profile exploration wells in Nigeria, Angola and Mozambique," said Martin Craighead, Baker Hughes President and Chief Executive Officer. "Our technology enabled us to differentiate on many important new contracts including a high-pressure, high-temperature Wireline contract in Europe, and an Artificial Lift contract for approximately 1,000 wells in Russia.  Furthermore, during the quarter we began work on our first Integrated Operations contract in Iraq, and we expect to see further growth in this business throughout the year. 

"As previously disclosed, margins in North America were lower than the fourth quarter due to challenges in the Pressure Pumping product line, including the rapid transition from natural gas to oil-directed drilling rig activity, the increasing supply of Pressure Pumping capacity across the market, as well as company specific supply chain challenges.  We are addressing our supply chain challenges by improving our distribution network, increasing supplies of critical raw materials and enhancing the utilization of our fleets and other critical assets," Craighead added.

"We expect to realize significant benefits from these improvements in the second half of 2012; however, it is clear that the overall market is experiencing pricing pressure that is likely to extend throughout 2012. 

"Our other product lines continue to post impressive revenue and operating results in North America," Craighead continued. "Our technological advantages across many of our product lines continue to drive superior performance, and the shift to oil-directed drilling has been very beneficial for our Drilling, Completions, Upstream Chemicals and Artificial Lift product lines." 

Debt increased by $449 million to $4.52 billion compared to the fourth quarter 2011. Cash decreased by $270 million to $780 million compared to the fourth quarter 2011. 

Capital expenditures were $671 million, depreciation and amortization expense was $363 million, and dividend payments were $65 million in the first quarter 2012.

Adjusted EBITDA (a non-GAAP measure) in the first quarter 2012 was $990 million, down $194 million sequentially.  A reconciliation of net income attributable to Baker Hughes to adjusted EBITDA is provided in Table 2. 

Supplemental financial information for revenue and adjusted operating profit before tax (a non-GAAP measure) is provided in Table 4.

Beginning in the first quarter 2012, the revenue and operating profit of Reservoir Development Services have been reclassified from the Industrial Services segment into the geographic operating segments where the work was performed.  All segment data in this press release reflects this updated classification.  The quarterly results for the last three years have been reclassified to reflect this change and are available online at: www.bakerhughes.com/investor in the financial information section.

Consolidated Condensed Statements of Income

(Unaudited)

(In millions, except per share amounts)

   Marketing, general and administrative

Net income attributable to noncontrolling interests

Net income attributable to Baker Hughes

Basic earnings per share attributable to Baker Hughes

Diluted earnings per share attributable to Baker Hughes

Weighted average shares outstanding, basic

Weighted average shares outstanding, diluted

Depreciation and amortization expense

Consolidated Condensed Balance Sheets

(Unaudited)

Property, plant and equipment, net

      Short-term borrowings and current portion of

          long-term debt

Deferred income taxes and other tax liabilities

Consolidated Condensed Statements of Cash Flows

(Unaudited)

Cash flows from operating activities:

Adjustments to reconcile net income to net cash flows from

   operating activities:

Other, primarily working capital

Net cash flows from operating activities

Cash flows from investing activities:

Expenditures for capital assets

Net cash flows from investing activities

Cash flows from financing activities:

Net proceeds (payments) of debt

Net cash flows from financing activities

Effect of foreign exchange rate changes on cash

Decrease in cash and cash equivalents

Cash and cash equivalents, beginning of period

Cash and cash equivalents, end of period

Table 1: Reconciliation of GAAP and Non-GAAP Financial Measures(1)

The following table reconciles net income attributable to Baker Hughes, which is the directly comparable financial result determined in accordance with Generally Accepted Accounting Principles (GAAP), to adjusted net income, which excludes certain identified items (a non-GAAP financial measure) referenced in this news release.  There were no identified items requiring adjustment for the first quarters of 2012 or 2011.

Three months ended December 31, 2011

(Unaudited)

(In millions, except per share amounts)

Net income attributable to Baker Hughes (GAAP)

Adjusted net income (non-GAAP)

Adjusted net income is a non-GAAP measure comprised of net income attributable to Baker Hughes excluding the impact of certain identified items.  The company believes that adjusted net income is useful to investors because it is a consistent measure of the underlying results of the company's business.  Furthermore, management uses adjusted net income as a measure of the performance of the company's operations.  Reconciliation of net income attributable to Baker Hughes, a GAAP measure, to adjusted net income for historical periods can be found in the Supplemental Financial Information on the company's website at: www.bakerhughes.com/investor.

Table 2:  Calculation of EBIT, EBITDA and Adjusted EBITDA (non-GAAP measures)(1)

Net income attributable to Baker Hughes

Net income attributable to NCI(2)

Earnings before interest and taxes (EBIT)

Depreciation and amortization expense

Earnings before interest, taxes, depreciation

   and amortization (EBITDA)

EBIT, EBITDA and Adjusted EBITDA (as defined in the calculations above) are non-GAAP measures. Management is providing these measures because it believes that such measures are widely accepted financial indicators used by investors and analysts to analyze and compare companies on the basis of operating performance.

Table 3: Segment Revenue, Profit Before Tax, and Profit Before Tax Margin(1)

Corporate and Other Profit Before Tax

Corporate, net interest and other

Profit before tax margin is a non-GAAP measure defined as profit before tax ("income before income taxes") divided by revenue. Management uses the profit before tax margin because it believes it is a widely accepted financial indicator used by investors and analysts to analyze and compare companies on the basis of operating performance.

Includes a charge of $315 million before-tax recorded in the fourth quarter of 2011 related to the impairment of certain trade names.  The impairment charge recognized in each segment is as follows:  North America - $105 million; Latin America - $64 million; Europe/Africa/Russia Caspian - $48 million; Middle East/Asia Pacific - $47 million; and Industrial Services - $51 million.

The revenue and profit before tax of Reservoir Development Services have been reclassified from the Industrial Services segment into the geographic operating segments.  Segment revenue and profit before tax for the three months ended March 31, 2011, and December 31, 2011, have been reclassified to reflect this change.

Table 4:  Supplemental Financial Information Excluding Certain Identified Items

The following table contains non-GAAP measures of operating profit before tax and operating profit before tax margin excluding impairment charges recorded in the fourth quarter of 2011 (see Table 3).  There were no items requiring adjustment for the first quarters of 2011 or 2012. 

Operating Profit Before Tax(1)

Operating Profit Before Tax Margin(1)

Operating profit before tax is a non-GAAP measure defined as profit before tax ("income before income taxes") less certain identified costs. Operating profit before tax margin is a non-GAAP measure defined as operating profit before tax divided by revenue. Management uses each of these measures because it believes they are widely accepted financial indicators used by investors and analysts to analyze and compare companies on the basis of operating performance and that these measures may be used by investors to make informed investment decisions.

 The revenue and profit before tax of Reservoir Development Services have been reclassified from the Industrial Services  segment into the geographic operating segments.  Segment revenue and profit before tax for the three months ended March 31, 2011, and December 31, 2011, have been reclassified to reflect this change.

Baker Hughes Operational Highlights

North America
Recently in U.S. Land, Baker Hughes deployed an 11-stage Frac-Point™ system with 22 newly developed multiport sleeves with DirectConnect ports.  This technology will allow fracture initiation from multiple ports in each isolated horizontal section to maximize reservoir contact.

Baker Hughes has installed a 30-stage OptiPort™ completion system in central Oklahoma.  Newly introduced OptiPort™ technology in U.S. Land  allows the customer to selectively choose where to locate the sleeve and initiate the fractures with an unlimited number of zones.  This technology saves time and lowers fluid consumption.

Baker Hughes continues to demonstrate its leadership position in the ultra-High Pressure/High Temperature (HP/HT) market  by setting the deepest liner to date in the Gulf of Mexico at 33,882 ft. (10,327 m)

In Canada, Suncor Energy awarded Baker Hughes the President's Operational Excellence Award for our Centigrade™  Ultra Temperature Electrical Submersible Pump.  This technology was awarded based on strategic alignment and technical excellence at Suncor's Firebag facility, which will enable substantial savings over the span of the three-year project.

Latin America
In Brazil, Baker Hughes completed drilling the first horizontal well in the pre-salt reservoir in the Lula field in the offshore Santos basin.  Our AutoTrak™ rotary steerable system and CoPilot™ real-time drilling optimization service were used in this well, which improved drilling efficiency by 75%.

In Brazil, our Kymera™ hybrid drill bit was used to drill a 26-in. (66 cm) section in a single run offshore in the pre-salt area.  The rate of penetration was 50% to 300% faster than offset wells. This new technology is a step change in cost and efficiency for operators in the pre-salt area.

In Argentina, Baker Hughes stimulated two unconventional wells in the southern region.

Europe/Africa/Russia Caspian
Baker Hughes continues to be a leader in the HP/HT Wireline market in the North Sea.  During the quarter, Baker Hughes had numerous operational successes, recorded record revenue and secured an important HP/HT contract to further strengthen this position.

Baker Hughes was awarded a two-year contract in the southern North Sea to provide 32 Cr16 Coiled Tubing velocity strings ranging from 3,500 to 5,000 meters in length.  Other services will include coiled tubing cleanouts, plug retrievals and nitrogen gas lifts.

Using our LWD tools in deepwater offshore Nigeria, Baker Hughes retrieved 60 test points from a 12 1/4-in. x 13 1/2-in. (31 cm x 34 cm) hole without pulling out of the hole.  This technology demand will continue to grow in deepwater Africa, and its reliability is critical in areas such as Mozambique, Ghana, Nigeria and Angola. 

In the Russia Caspian area, Baker Hughes signed a $100 million, three-year Artificial Lift contract with a major operator.  The contract scope includes approximately 1,000 wells over three years.  Baker Hughes' complete Artificial Lift and Oil Pump Services portfolio and experience with repairing Russian ESP systems were critical factors in winning this contract.

Middle East/Asia Pacific
In Australia, Baker Hughes was awarded a three-year liner hanger and wireline contract to service wells offshore Western Australia in the harsh-environment deepwater area.

In China, Baker Hughes Pressure Pumping and Completion Services completed a 20-stage, openhole, multistage fracturing operation, the second of a 12-well campaign.  The unconventional market continues to grow with another commitment for 20 FracPoint™ systems from a NOC.

In Vietnam, Baker Hughes was awarded a contract for multiple service lines including Drilling Services, Wireline, Cementing and Fishing Services by a major IOC.  This contract solidifies Baker Hughes as a major provider of Drilling and Evaluation services in the deepwater segment of Southeast Asia.

Supplemental Financial Information
Supplemental financial information for the first quarter 2008 through the first quarter 2012 can be found on our website at: www.bakerhughes.com/investor in the financial information section.

Conference Call
The Company has scheduled a conference call to discuss management's outlook and the results reported in today's earnings announcement.  The call will begin at 8:30 a.m. Eastern time, 7:30 a.m. Central time, on Tuesday April 24, 2012, the content of which is not part of this earnings release.  A slide presentation providing summary financial and statistical information that will be discussed on the conference call will also be posted to the company's website and available for real-time viewing. To access the call, please call the conference call operator at 800-374-2469, or 706-634-7270 for international calls, 20 minutes prior to the scheduled start time and ask for the "Baker Hughes Conference Call."  A replay of the call will be available through Tuesday, May 8, 2012. The number for the replay is 855-859-2056 in the United States, or 404-537-3406 for international calls, and the access code is: 59811229. To access the webcast, go to: http://www.bakerhughes.com/investor.

Forward-Looking Statements
This news release (and oral statements made regarding the subjects of this release, including on the conference call announced herein) contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, (each a "forward—looking statement").  The words "anticipate," "believe," "ensure," "expect," "if," "intend," "estimate," "project," "forecasts," "predict," "outlook," "aim," "will," "could," "should," "potential," "would," "may," "probable," "likely," and similar expressions, and the negative thereof, are intended to identify forward—looking statements.  There are many risks and uncertainties that could cause actual results to differ materially from our forward-looking statements.  These forward-looking statements are also affected by the risk factors described in the company's Annual Report on Form 10-K for the year ended December 31, 2011 and those set forth from time to time in other filings with the Securities and Exchange Commission ("SEC").  The documents are available through the company's website at http://www.bakerhughes.com/investor or through the SEC's Electronic Data Gathering and Analysis Retrieval System (EDGAR) at http://www.sec.gov.  We undertake no obligation to publicly update or revise any forward—looking statement.

Our expectations regarding our business outlook and business plans; the business plans of our customers; oil and natural gas market conditions; cost and availability of resources; economic, legal and regulatory conditions and other matters are only our forecasts regarding these matters.

These forward looking statements, including forecasts, may be substantially different from actual results, which are affected by many risks including the following risk factors and the timing of any of these risk factors:

Economic conditions — the impact of worldwide economic conditions and sovereign debt crises in Europe; the effect that declines in credit availability may have on worldwide economic growth and demand for hydrocarbons; the ability of our customers to finance their exploration and development plans; and foreign currency exchange fluctuations and changes in the capital markets in locations where we operate.

Oil and gas market conditions — the level of petroleum industry exploration, development and production expenditures; the price of, volatility in pricing of, and the demand for crude oil and natural gas; drilling activity; drilling permits for and regulation of the shelf and the deepwater drilling; excess productive capacity; crude and product inventories; LNG supply and demand; seasonal and other adverse weather conditions that affect the demand for energy; severe weather conditions, such as tornadoes and hurricanes, that affect exploration and production activities; Organization of Petroleum Exporting Countries ("OPEC") policy and the adherence by OPEC nations to their OPEC production quotas.

Terrorism and geopolitical risks — war, military action, terrorist activities or extended periods of international conflict, particularly involving any petroleum—producing or consuming regions; labor disruptions, civil unrest or security conditions where we operate; expropriation of assets by governmental action; cybersecurity risks and cyber incidents or attacks.

Price, market share, contract terms, and customer payments — our ability to obtain market prices for our products and services; the ability of our competitors to capture market share; our ability to retain or increase our market share; changes in our strategic direction; the effect of industry capacity relative to demand for the markets in which we participate; our ability to negotiate acceptable terms and conditions with our customers, especially national oil companies, to successfully execute these contracts, and receive payment in accordance with the terms of our contracts with our customers; our ability to manage warranty claims and improve performance and quality; our ability to effectively manage our commercial agents.

Costs and availability of resources — our ability to manage the costs, availability, distribution and delivery of sufficient raw materials and components (especially steel alloys, chromium, copper, carbide, lead, nickel, titanium, beryllium, barite, synthetic and natural diamonds, sand, gel, chemicals, and electronic components); our ability to manage energy-related costs; our ability to manage compliance-related costs; our ability to recruit, train and retain the skilled and diverse workforce necessary to meet our business needs and manage the associated costs; the effect of manufacturing  and subcontracting performance and capacity; the availability of essential electronic components used in our products; the effect of competition, particularly our ability to introduce new technology on a forecasted schedule and at forecasted costs; potential impairment of long-lived assets; the accuracy of our estimates regarding our capital spending requirements; unanticipated changes in the levels of our capital expenditures; the need to replace any unanticipated losses in capital assets; labor-related actions, including strikes, slowdowns and facility occupations; our ability to maintain information security.

Litigation and changes in laws or regulatory conditions — the potential for unexpected litigation or proceedings and our ability to obtain adequate insurance on commercially reasonable terms; the legislative, regulatory and business environment in the U.S. and other countries in which we operate; outcome of government and legal proceedings as well as costs arising from compliance and ongoing or additional investigations in any of the countries where the company does business; new laws, regulations and policies that could have a significant impact on the future operations and conduct of all businesses; laws, regulations or restrictions on hydraulic fracturing; any restrictions on new or ongoing offshore drilling or permit and operational delays or program reductions as a result of the new regulations in the Gulf of Mexico and other areas of the world; changes in export control laws or exchange control laws; the discovery of new environmental remediation sites; changes in environmental regulations; the discharge of hazardous materials or hydrocarbons into the environment; restrictions on doing business in countries subject to sanctions; customs clearance procedures; changes in accounting standards; changes in tax laws or tax rates in the jurisdictions in which we operate; resolution of tax assessments or audits by various tax authorities; and the ability to fully utilize our tax loss carry forwards and tax credits.

Baker Hughes is a leading supplier of oilfield services, products, technology and systems to the worldwide oil and natural gas industry. The company's 58,000-plus employees today work in more than 80 countries helping customers find, evaluate, drill, produce, transport and process hydrocarbon resources. For more information on Baker Hughes' century-long history, visit: www.bakerhughes.com.

Investor Contact:
Adam B. Anderson, +1.713.439.8039, adam.anderson@bakerhughes.com
Eric S. Holcomb, +1.713.439.8822, eric.s.holcomb@bakerhughes.com
Media Contact:
Teresa Wong, +1.713.439.8110, teresa.wong@bakerhughes.com

SOURCE Baker Hughes

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Drilling & Completion Tech Digest

Single bit drills intermediate section of Tattoo field

Single bit drills intermediate section of Tattoo field

A single Ulterra polycrystalline diamond compact bit has drilled the entire intermediate section of the Tattoo field in Northwest Canada. An 8.5-in. (216-mm) U513M drilled both the vertical and build sections with the same bottomhole assembly, saving the operator two trips and $570,000 compared with the average of six section offsets in the field in March.

U513M maintains high instantaneous rates of penetration required in the drill-out, as well as the ability to aggressively build angle with tool face control.

Darcy installs downhole sand control system

Darcy Technologies recently installed its next-generation sand control system about 1,000 ft below the surface.

Darcy Technologies recently completed the first downhole installation of its next-generation sand control system following the success of a robust system integrity test in Aberdeen, which was supported by several global operators and an international oilfield service company.

Darcy’s sand control system was run from a land rig integrating it with standard third-party completion accessories to make up the full sand face completion system. The system was placed on depth and set into a variable wellbore some 1,000 ft below the surface.

The system’s construction and high collapse resistance provides a solution for low pressure, shallow and heavy oil reservoirs. The solution can be used in remote or environmentally sensitive locations because gravel pack fluids, pumping equipment, installation and excess personnel are eliminated from the process, and its modular design is integrated with common completion equipment.

The system’s activation by applying pressure from surface eliminates the time, effort and cost of gravel pack completions.

CNPC, Shell sign China’s first shale gas PSC

China National Petroleum Corp (CNPC) and Shell China have signed a production-sharing contract (PSC) for shale gas exploration, development and production in the Fushun-Yongchuan block in the Sichuan Basin.

Subject to government approval, this is the first shale gas PSC signed in China. The contract area covers approximately 3,500 sq km. Shell will apply its technology, expertise and experience.

“We are delighted about this new milestone in our strategic cooperation with CNPC. China has huge shale gas potential, and we are committed to making a contribution in bringing that potential into reality,” Peter Voser, CEO of Royal Dutch Shell, said.

Service diagnoses drilling challenges ahead of time

A new Baker Hughes service identifies potential drilling issues before they occur by pinpointing similar case histories in real time using a global library of drilling practices and expert advice to provide operators with suggestions on how to respond or take corrective actions while drilling.

WellLink Radar Remote Drilling Advisory Service is an integrated solution that uses case-based reasoning and event detection. It leverages Verdande Technology’s DrillEdge software to reduce uncertainty, minimize nonproductive time and increase safety. The service allows for the remote monitoring of multiple wells simultaneously and enhances drilling efficiency.

At-bit inclination technology optimizes well placement

PathFinder, a Schlumberger company, recently introduced the iPZIG at-bit inclination, gamma ray and imaging service. iPZIG helps optimize well placement in target zones through early bed boundary detection.

Developed for unconventional oil and gas markets and high-efficiency drilling applications, the iPZIG service allows for greater directional control and accuracy while drilling versus conventional technologies, with sensors placed directly behind the drill bit. Using data from the iPZIG service, changes in lithology and bottomhole assembly orientation are quickly identified.

ABB to supply vessel with DC-based power grid

ABB recently won an order from ship owner Myklebusthaug Management to supply the first direct-current (DC) power grid onboard a ship. The equipment will allow a new offshore platform support vessel, under construction in Norway, to operate at the highest energy efficiency level to minimize emissions.

The Onboard DC Grid will allow vessels to cut fuel consumption and emissions by up to 20%

The May/June issue of Drilling Contractor featured coverage of the 2012 OTC Spotlight on New Technology Awards. This article can be found in its entirety here.

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Dashboard concept aims to facilitate diagnostics, decision-making on BOPs

High-level ‘traffic light’ status would allow users to know when critical functions are impaired

By Jim McKay, Allen Pere, BP; Clayton Simmons, Mike Doty, National Oilwell Varco; Tony Hogg, Ensco; Gavin Starling, Rock Oilfield Group

Figure 1: Traditional MUX BOP control system diagnostics are geared toward maintenance and troubleshooting more than operational decision-making. A BOP dashboard concept is being studied that would improve communications among operations personnel, contractors and the OEM to assess BOP health issues.

As every motorist knows, a vehicle’s dashboard is an important interface that alerts the driver of real-time changes regarding certain car engine “health” metrics and alerts the driver that the engine may need to be serviced. While not a diagnostic tool in and of itself, the dashboard serves to alert the driver that a performance or health issue may exist.

Blowout preventer (BOP) equipment is designed to secure the well, and a BOP’s health is critical to ensuring that it works as designed. A real-time BOP dashboard can improve communication between operations personnel, rig contractor subsea engineers and the original equipment manufacturer (OEM) to assess potential BOP health issues.

This article describes a development process for a BOP dashboard and discusses the potential benefits, challenges and lessons learned associated with implementing a BOP monitoring system.

Traditional multiplex (MUX) BOP control system diagnostics (Figure 1) are designed by OEMs for use by personnel proficient in BOP control systems, such as a rig contractor’s subsea engineer. Control system diagnostics are generally geared toward maintenance and troubleshooting system problems more than operational decision-making.

Traditionally, the BOP diagnostic data is solely available at the rig-based engineering work station (EWS), also known as the event logger. Historically BOP data is not exchanged to shore from the offshore event logger. The industry could benefit from having BOP control system integrity or BOP health presented in a manner that allows operations people (offshore and onshore) to participate in communication with BOP experts to assess any risk associated with the BOP and the BOP control system.

The Concept

The BOP dashboard (Figure 2) aims to simplify complex BOP diagnostics in an easy-to-understand format that facilitates a joint assessment of the issue. In early 2011, BP, Ensco and National Oilwell Varco (NOV) collaborated on a project to consider preliminary development of a BOP dashboard that takes existing alarms, analog data and events from the BOP EWS and translates them into a high-level “traffic light” status. The traffic light logic is based on levels of system redundancy that allow the user to understand when critical functions are impaired.

The first phase of the project focuses on the electrical components of the control system, with further extension to the hydraulic components in the subsequent phases of the project. Although the initial dashboard would rely solely on the NOV eHawk platform, the end product could be a BOP monitoring dashboard incorporated into a mud-logging network.

When integrated with the common mud-logging database, the BOP data could be interconnected with other real-time well construction systems, such as digital BOP pressure-testing technology.  If a BOP health issue should arise, the OEM web platform can provide additional layers of detail beyond the dashboard.

These additional layers should provide the user the same screens that are already available in the offshore BOP diagnostic system. Such a system can also be designed to allow near real-time archiving of raw BOP data on an onshore computer and can produce a BOP health report.

Although this system is not designed for or intended to be used for continuous monitoring, the end user can view the dashboard at any time, and reports summarizing alarm and event information can be sent automatically to select users.

Thus, this system could be a useful tool for well-site leaders (including the company man), offshore installation managers or shore-based operations teams. For example, operations teams could use this system to review applicable BOP health attributes prior to each daily rig call.

Software, Hardware Development and Installation

In this project, the EWS must be configured to allow for data export to the eHawk server. Although historically SQL data was used, NOV determined that the interoperability standard for automation (OPC) provided advantages for configuration. OPC has the ability to queue data and push an initial state for BOP positions and outstanding alarms. This is important when data transfer is lost or upon initial installation of the BOP monitoring system. OPC simplified the configuration by not requiring manual entry of outstanding alarms and initial positions into the eHawk database.

Figure 3 shows a simplified system diagram of the connection between the EWS, the eHawk server and the relevant Sitecomm server.

For the installation, NOV had to update the OEM drawings to show the new connection from the EWS and the eHawk server. The BOP control system had to be recertified from American Bureau of Shipping to reflect this change.

‘Traffic Light’ Development

The OEM holds the unique system knowledge required for traffic light logic development. For example, the OEM can provide guidance on the meaning of alarms and system redundancy. The operator and rig contractor can define the levels of risk that would be associated with each level of traffic light.

Figure 2: Several companies have looked at developing a BOP dashboard that aims to simplify complex BOP diagnostics. The dashboard would take existing alarms, analog data and events from the BOP engineering work station and translate them into high-level traffic light status. The traffic light logic is based on levels of system redundancy that allow the user to understand when critical functions are impaired.

Originally three automated tiers of colors were envisioned to provide the health status of the BOP. “Red” status would mean no functionality, “yellow” status would mean functional but no redundancy, and “green” status would be fully functional and with redundancy.

As the BOP owner, the rig contractor may wish to retain the ability to manually change the traffic light severity due to the potential for false-positive or false-negative traffic lights. For example, it is possible that due to interdependencies between alarms, a minor alarm could also trigger a more severe alarm. In those instances, the dashboard traffic lights can be manually changed from a more severe status to a less severe status. The manual override can be done for a specific alarm, and the related traffic lights will be identified by an “F” indicating the traffic light was forced to a more or less severe status. To manually force or clear any alarm, the user is forced to enter a description that details the reason for the force.

In addition to a management of change process, this information allows for future review and oversight. The forcing of alarms, not traffic lights, allows subsequent alarms to change a traffic light status with an “F” to an increased severity level.

In addition, the user can scroll over a traffic light to view the outstanding alarms and to identify those alarms that were forced.

Different parts of the control system may have different levels of redundancy. In this project, at a minimum, redundancy for a specific BOP function is required for the traffic light to be green. An example of redundancy is the use of dual pods (yellow and blue). An example of dual redundancy would be communications to the pods. Each pod receives redundant communications, and the pods themselves are redundant; hence each pod receives a spare communication link to the surface control system.

For the BOP system, if the component is shared by the pod, then redundancy is required. If the component is specific to the pod, then redundancy is not required.

The current traffic light logic development used in this project omitted alarms related to the hydraulic system data (Phase II) or minor alarms (e.g., stuck push button alarms).

Dashboard GUI Development

When developing the graphical user interface (GUI) for the dashboard, the target users were assumed to include both experienced subsea engineers and those on an operations team with only a rudimentary knowledge of the BOP control system.

Starting in the top left of the dashboard and working to the bottom right, the following design requirements were built in the dashboard for this project:

• Top left – The last test date for auditing purposes will be manually entered and recorded.

• Upper left – Leaks and hydraulic issues will be detected with logic (Phase II development) and reported with a traffic light status.

• Lower left – Emergency systems status will be based on the solenoid valve health.

• Bottom left – Event log data will capture raw commands in a table with volumes, times for the activation and the location of the command.

• Bottom left – Outstanding alarms will capture raw alarm data, the time of the first alarm, the number of alarms in the last 24 hours, time of the last alarm acknowledgement and location of the last alarm acknowledgement.

• Bottom left – MUX fiber will report multiplex fiber health based on existing alarms.

• Bottom left – Surface alarms and subsea alarms will report all alarms and sort them based on the location of the equipment. This will allow the user to understand if the BOP stack should be pulled in the event of a yellow health status on a specific BOP function. These are envisioned as all-inclusive alarm traffic lights regardless of redundancy or alarm severity. This will also allow the user to understand if a minor alarm has been triggered.

• Middle left – Read back pressures will report the analog pressure for each specific function closing pressure. For example, this will allow the user to understand if the closing pressure was increased to obtain a seal.

• Middle – BOP function health separated by yellow and blue pods. Each major BOP function will have a displayed traffic light health indicator for each pod. The active pod will be indicated by a traffic light that is 50% larger than the non-active pod.

• Middle – BOP positions will be viewable by colored circles and blocks that animate physical position of the rams, annulars and subsea BOP valves.

• Right – Chronology log will display the positions and the overall health of the system over a 24-hr period. If the user is not constantly monitoring the BOP dashboard, they can look back at a high level to understand if the BOP was functioned or if there was a BOP health issue.

Figure 3: The engineering work station, or event logger, had to be configured to allow for data export to the eHawk server. This figure shows a simplified system diagram of the connection between the EWS, the eHawk server and the relevant Sitecomm server.

Monitoring and Decision-Making

The real-time BOP dashboard will only be used as a communication tool by facilitating conversation between operations teams on BOP health issues. The primary diagnostic system will remain the original rig-based OEM EWS. The workflow process (Figure 4) requires that the EWS be used to confirm the dashboard before making any decisions.

One item that the project considered in the workflow process was the need to avoid uncontrolled distribution of data to individuals that may not fully understand the significance of various alarms. Not all alarms are equally important, and this distinction must be addressed when working with the dashboard.

Part of the pilot intent is to develop a decision tree protocol (Figure 5) where operations teams can make standard operation decisions. This will help eliminate the potential for subjective BOP health resolutions. Ideally, all BOP health scenarios would be mapped with a decision tree; however, it is more realistic to assume that some alarms will not fully reflect the true health of the BOP.

Once an alarm is triggered, the rig crew will need to confirm the BOP health issue by troubleshooting the issue. For example, if a MUX fiber signal triggers an alarm indicating fiber degradation, the crew will be able to perform a decibel loss test to confirm the issue.

For this version of the console, the decision protocol was set at a level to allow operations teams to determine the health status and remedial action. By allowing the user to manually change the health rating, the user can override the automated traffic light logic.

In time, as the diagnostic system and traffic light logic is accepted by the operations teams, the ability to manually override the BOP health status may be eliminated. For example, a future operations decision tree could have a defined scenario that requires the BOP to be pulled if a blind shear ram solenoid valve becomes inoperable.

Pilot Program

The milestones for the pilot program will be:

1. Sending alarm and event data back to shore.

2. Developing a working dashboard.

3. Potentially using the dashboard for decision-making and learning from that experience.

As stated previously, Phase I of the technology will focus strictly on the MUX electrical system; however, Phase II will include hydraulic diagnostics.

Digital security processes and hardware are long lead items that require careful planning for the first installation. An installation plan cannot be finalized until rig surveys are complete. The monitoring system can only be installed between wells when the BOP is on surface.

The major challenge and learning in this pilot program will be when the rig contractor and operator disagree on the BOP health status or the proposed remedial action of a BOP health issue. As this technology is adopted, it is anticipated that these situations will be addressed through agreed upon policies and procedures or decision trees.

Figure 4: The primary BOP diagnostic system will remain the rig-based OEM EWS, with the real-time BOP dashboard used as a communication tool for facilitating conversations between operations teams on BOP health issues. The workflow process requires that the EWS be used to confirm the dashboard before making any decisions.

The Way Forward

The hydraulic system will be addressed in Phase II by creating high-level traffic lights for leak detection and pressure vessel health. Leak detection methods include mix pump cycles, hydraulic fluid usage and flow measurements. In addition, each BOP function uses a specific volume that can be measured and compared with a previous baseline for leak detection.

Advancing the diagnostics with better sensors or algorithms will further develop the BOP dashboard. Ram position sensors, tool joint position sensors, BOP cameras and additional BOP wellbore pressures are examples of potential sensor upgrades.

The BOP dashboard data can eventually be integrated with the digital BOP pressure testing. This will allow the rams that were functioned to be identified for the pressure-testing data. Numerous key performance indicators (KPI’s) also can be calculated as more real-time data is gathered. For example, the number of cycles on a solenoid valve or the frequency of successful annular pressure tests can be captured.

These KPI’s and other collected data might eventually be shared amongst the industry through existing organizations, such as Offshore Reliability Data. This collective industry data can provide more robust fault tree analysis that could potentially provide real-time probability of “failure on demand” when certain functionality is lost.

Drilling Contractor Perspective

As the “big crew change” begins, more and more of the highly experienced subsea engineers are transferring to shore-based, or auditor-type, positions, challenging the industry to develop competent replacements. A well setup dashboard, supported by an agreed detailed decision tree, will allow these shore-based experts to better assist the rig-based subsea engineers to diagnose any problems, to discuss the issues with their client counterparts and to decide the most sensible path forward.

The BOP dashboard will not reduce the need for development and training of the rig-based subsea engineers. The BOP dashboard can only report the “health” of the system. It cannot, by itself, do anything to maintain its condition; this has to come from the allocation of sufficient time and resources, between each well, to properly maintain and test all of the subsystems.

This equipment can only be maintained and operated to the standards to which it was designed and manufactured (API 16D 2nd Ed.), regardless of the ease of monitoring afforded by the BOP dashboard. Improvements in BOP and BOP control system designs by the OEMs will be important factors in realizing future reliability enhancements.

Figure 5: A possible operations decision tree for the pilot shows where operations teams can make standard operational decisions. This would eliminate the potential for subjective BOP health resolutions. Ideally, all BOP health scenarios would be mapped with a decision tree.

OEM Perspective

Transferring the most up-to-date and accurate information back to the OEM allows the company to design more reliable equipment, as well as provide appropriate support to the customer. In the past, this was done over the phone, by email or required travel to the rig. Using this tool, OEMs can look at BOP information in near real time and better assist in decisions regarding the safe and proper operation of the equipment.

Summary

A BOP dashboard that simplifies existing diagnostics and allows for remote monitoring of the subsea BOP control system will improve communication of BOP health. Future deployments of the BOP dashboard could serve as a common platform across rig fleets that allow standardization of BOP diagnostic data and aids in operational decision making.

This article is based on IADC/SPE 151182, “Blowout Preventer (BOP) Health Monitoring,” presented at the 2012 IADC/SPE Drilling Conference and Exhibition, San Diego, Calif., 6–8 March 2012.

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