By Fred Ng, Wild Well Control

Figure 1 shows kick simulations of a gas kick circulation using the Driller’s Method in a 27,300-ft HPHT well with 15-ppg mud weight, a 0.7-ppg x 80 bbl kick and a kill rate of 200 gal/min, with synthetic oil-based mud.

Events in recent years have heightened industry awareness regarding well control issues, especially high-pressure, high-temperature (HPHT) and deepwater drilling operations, which are becoming increasingly common in many parts of the world. Risk management involves developing mitigation and contingency options for identified risks. This article addresses applicable engineering tools that have resulted from development of advanced technologies in recent years. These tools include multiphase simulations to address well planning and kick tolerance evaluation for mitigation options, as well as simulation of blowouts and dynamic kill for contingency planning. They can be applied to land or offshore operations. The advanced technologies enable complete modeling of detailed conditions in the wellbore during kick circulation, blowout and dynamic kill. Case histories will illustrate and highlight such applications. Discussions will also include recent developments in equipment and systems for capping subsea blowouts, some of which are now in place for various regions globally.

Risks of many kinds are inherent in the hydrocarbon extraction business, and both operators and the service sector are expected to be diligent in making decisions regarding these risks. In particular, well control is an ever-present risk that requires continuity of vigilance both in time and phases of operations. These measures begin with pressure management in well design and operations on a day-to-day basis. A failure in pressure management can lead to a pressure control event where unconventional well control procedures and special expertise may be needed to handle scenarios such as an underground blowout. A blowout results from failure in pressure management and/or pressure control and may lead to extensive intervention efforts, as well as a relief well and dynamic kill.

Pressure management

Figure 2 shows kick simulations from the same case as in Figure 1 but with water-based mud. The choke pressure plot (center bottom) demonstrates that free gas migration in water-based mud continues even when a kick is shut in, resulting in equally rapid pressure buildup throughout the wellbore.

Wellbores are designed and constructed to manage expected formation pressures.  Typical elements for the planning phase include evaluation of pore pressure, fracture gradient, mud weight, casing design and depth selection.  In operations, the measures include monitoring well behavior and making adjustments to manage the pressures. Multiphase transient simulation for kick tolerance and other parameters is now available to meet the critical need for determination of a well’s capacity to handle kicks and other well control scenarios.

Pressure control

This occurs when pressure management has been compromised by unexpected formation pressure or operational conditions. It can also result from complications, such as drill string washout, bit plugging or formation bridging, in an otherwise standard kick circulation.  This often results in handling kicks with simultaneous losses or underground blowout, leading to a variety of unconventional well control operations that is best conducted by well control professionals. Multiphase simulations play an increasingly critical role in evaluation and design for pumping, bleeding and other options involved in these operations.

Blowout

A blowout results from failure in pressure management and/or pressure control and often leads to extensive intervention efforts, as well as relief well and dynamic kill. Advanced multiphase simulation is now available to support these efforts in a format that is suitable for practical application. Results include kill mud weight, volume required, kill rate, pump pressure, hydraulic horsepower and other critical factors. Such  simulation is now also used widely to meet operator or government requirements for contingency planning, providing information on viability, design and operational requirements of the kill operation needed to resolve a blowout scenario.  Equipment and systems for mud line intervention in subsea blowouts have also been developed for debris removal, dispersant application and blowout preventer (BOP) capping. They are now in place for various regions.

Figure 3 maps a simulation for the blowout and dynamic kill of a 28,000-ft well. The well unloads until a steady-state blowout is established at about the 60-minute mark. Dynamic kill is initiated and pumped until completion.

Multiphase kick simulation is available to provide analysis of kick tolerance and other critical parameters, both for the well design and operational phase. Results are more accurate and versatile than the traditional single bubble calculations. The latter cannot include effects of compressibility and solubility of gas in oil-based mud systems, which are increasingly used in industry for the current generation of wells in HPHT environments. It involves a complete time transient multiphase flow simulator that models the full dynamic behavior of the wellbore and its contents. The model simulates a kick from time of influx, through flow check, shut-in and subsequent kill operations.

One typical application is kick tolerance evaluation. The technology allows such evaluation to be based on circulating out, not just shut in, of well kicks over a range of magnitudes and sizes. It can be used for both well planning and updating well design when conditions change during operations, such as target depth, pressure, mud weight or leak-off test results. Data from these simulations, which typically ran for all hole sections drilled through the BOP, can also be used to evaluate casing design, as well as surface well control equipment.

These simulations have been used often to support real-time well control operations. Results can be available within minutes for a well with a model that has been set up during its planning. A graphic output such as shown in Figure 1 can be transmitted both to the rig and the planning team in the office, thus facilitating the technical discussions that are typically needed in planning the kill operations. The simulations can be used to provide modeling and evaluation of different well control procedures besides standard kill methods, including extended shut in before or during a kill, volumetric kill to bleed gas to surface and maintain constant bottomhole pressure, and losing returns during a kill.

The kick simulations described in this article are run with the Drillbench simulator provided by SPT Group. Figures 1 and 2 show result graphics from an example of gas kick circulation, using Driller’s Method in a 27,300-ft HPHT well, with 15.0-ppg mud weight, a 0.7-ppg x 80 bbl kick and a kill rate of 200 gal/min.  The case with synthetic oil-based mud (SOBM) is shown in Figure 1, and the same case with water-based mud (WBM) is shown in Figure 2.

Maximum choke pressure

This occurs when the top of the influx reaches surface. The pressure with SOBM is 1,250 psi, which is lower than the 1,350 psi seen at initial shut-in. With WBM, the trend is reversed, where the respective pressures are 2,200 psi and 1,450 psi. The main cause of the different trends is gas solubility in SOBM, which keeps the gas in solution until it reaches bubble point at about 3,500 ft, with free gas at less than 2% by volume at the surface just upstream of the choke. Much of the 11,500-ft influx column at that point is still dissolved in the relatively dense gas cut mud of 13.5 ppg. Gas solubility in WBM is lower, resulting in a free gas column of some 18,000 ft, with free gas reaching 30% by volume at the surface.

Pit gain

Table 1: A summary of design results from the simulation in Figure 3.

In the case with SOBM, the dissolved gas continued to diffuse and stretch out in the mud column as it is circulated up the hole. The result is continuous reduction of gas cut in the mud column, causing pit volume to shrink from the initial 80 bbl down to 70 bbl before the influx reached surface. Since gas is much less soluble in WBM, the free gas has to be allowed to expand in order to maintain constant bottomhole pressure, resulting in an opposite trend where pit volume increased to 100 bbl.

Gas migration

Gas migration occurs only when it is present in the form of free gas. In water-based mud, it occurs typically at the rate of 2,000 ft/hr to 3,000 ft/hr. In this case, the result is that the influx reached surface some four hours sooner in WBM than SOBM. Free gas migration in water-based mud continues even when a kick is shut in, resulting in equally rapid pressure build up throughout the wellbore, such as seen in the choke pressure plot in Figure 2.

If a kick in WBM has to remain shut in for an extended period, standard procedures such as volumetric kill should be applied to bleed off such pressure buildups accordingly to maintain constant bottomhole pressure and thus avoid breaking down the shoe. In the absence of such precautionary measure, it is not unusual to see a kick that otherwise could have been circulated out evolve into a complicated scenario of having to deal with underground crossflow.

For the same reason, it would be advisable to specify a limit for the initial shut-in period when evaluating kick tolerance in water-based mud. Typically, a period of 15 minutes or so should be sufficient for a crew to shut in the kick, note pressures and volumes and start volumetric or driller’s method operations.

Surface mud weight (SMW) versus equivalent static density (ESD)

Multiphase simulation provides complete modeling of the effects of temperature, compressibility, gas solubility and hydraulics under all conditions throughout the wellbore. These effects cannot be easily included in the simpler traditional models, which basically treat all kicks as single bubble water-based mud scenario. Under static conditions, the simulations provide a profile of the in-situ mud weight as well as ESD for the wellbore. In a typical HPHT well of over 25,000 ft, the SMW/ESD ratio in SOBM can be 17.5/17.7 ppg, versus 17.5/17.1 ppg for WBM. The reverse in trend is due to the difference in thermal expansion and compressibility of base oil versus water and can be critical factors in evaluating kick tolerance under these conditions.

Figure 4: The main components of this subsea containment system include debris clearing equipment, primarily the hydraulic shears to cut the debris around the well; a subsea dispersant system that includes distribution manifolds, hoses and applicators; an 18 ¾-in. 15,000-psi capping stack for well isolation; and a subsea hydraulic power unit that delivers up to 50 gal/min at 5,000 psi. The equipment are all modularized for air transport by cargo aircraft.

The multiphase flow involved in a blowout evaluation and dynamic kill design is very complex and can only be analyzed by transient flow simulations that take into account all the physical effects involved. The graphics in Figure 3 show a simulation for the blowout and dynamic kill of a 28,000-ft well. The well unloads until a steady-state blowout is established at about the 60-minute mark. Dynamic kill is initiated and pumped until completion, with the four windows on the left displaying pressure and flow rate data for the blowout well, and three on the right showing behavior of the relief well.

The simulations described in this article are run with the OLGA Advanced Blowout Control simulator, which was developed in a cooperative effort between Wild Well Control and SPT Group. It involves the latest technology in transient multiphase simulation and is particularly useful for today’s deep, HPHT and prolific wells.

While a parametric dynamic kill design can be developed for contingency planning, the actual design often has to be modified and established based on the circumstances of the blowout event and availability of equipment. For example, the maximum pump rate of 100 bpm in this case is likely to require special equipment and design for the surface spread, as well as for mixing, handling, transportation and storage facilities to support the kill. One operator is currently considering the design of a subsea kill spool in order to deliver such kill rate to the wellbore.

Blowout rate

This depends heavily on reservoir properties, as well as wellbore conditions and the scenario to be addressed, and is simulated as part of the dynamic kill design. For example, it can be an unrestricted or restricted flow and can range from blowout above the water line for a jackup to an uncontrolled flow from a wellhead on the sea floor.

Off-bottom kill

Depending on the distance of the intersect above the blowout zone, the required pump rate, kill mud weight and equivalent circulating density (ECD) for an off-bottom kill will all be significantly higher than for a kill on bottom. For example, kill mud weight and ECD can both exceed formation fracture gradient in the open hole, resulting in massive losses. If identified by simulation runs during the planning phase for the original target well, this problem may be addressed by running a deeper or additional string of casing or liner. Otherwise, options may be very limited if a blowout occurs.

Pump rate and control

In most cases, the blowout generates a substantial draw down in the original wellbore, resulting in a strong U-tube action whenever it is intercepted by the relief well. All efforts will be needed to prevent the relief well from unloading, by keeping the relief well full at a high pump rate. After the initial U-tube, pump pressure rises steadily as kill mud continues to fill the blowout wellbore. Pump rate must then be reduced in order to maintain wellbore pressure below fracture gradient and to keep pump pressure within ratings of the surface equipment. In this case, the operator had set a pump pressure limit of 7,500 psi, and the simulation shows how pump rate can be continuously stepped down to match it.

A statement from the US oil and gas regulatory agency BOEMRE highlights the need for such equipment: “To date, the primary deficiency that BOEMRE has identified in its review of OSRPs (oil spill response plans) is the lack of sufficient subsea containment equipment and other resources.” One such system recently made available is rated for 10,000-ft water depth and provides the equipment described below, which are modularized for air transport by cargo aircraft such as Boeing 747 or Antonov 124.  Figure 4 shows the individual components.

Debris clearing equipment

Main components are hydraulic shears to cut the debris around the well. In the event that the rig’s lower marine riser package fails to separate during emergency disconnect, there is a high probability that the riser and other debris will hinder installation of the capping stack onto the primary drilling BOP.  The largest of these shears typically has a jaw opening of 46 in.

Subsea dispersant system

The system includes the distribution manifolds, hoses and applicators needed to deploy dispersant subsea. Subsea application of dispersant may reduce the amount of oil coming to the surface. This in turn could result in reduced exposure of surface vessels and personnel to volatile organic compounds of the oil. It may also reduce the need for surface recovery or in-situ burn, as well as expensive surface dispersant operations that can involve multiple vessels and/or aircrafts.

Capping stack

A capping stack is a contingency device for well isolation used to cap a blowing well or to provide an engineered interface for flowback and disposal. It can be employed in the event of failure of the primary drilling BOP to shut in a well. It is mated to the primary BOP stack by connecting to the top profile of the BOP using a compatible connector.  Once mated, the well can be shut in with the two blind/shear rams. Flowback to surface capture and disposal vessels can be conducted through its four 3-¹/16 in. outlets. This is similar to the capping stack that successfully capped the deepwater blowout in the Gulf of Mexico in 2010.

Subsea HPU

This hydraulic power unit system delivers up to 50 gal/min at 5,000 psi and includes equipment for launch and recovery, deployment winches, as well as a surface control cabin. It is a complete stand-alone package, powered via dedicated remote operating vehicle (ROV) umbilical, and includes a control system that linearly adjusts the flow and pressure for each hydraulic output. The system is based on proven ROV technology, including acoustic monitoring of the capping stack pressure sensors, as well as back-up pumps to provide emergency hydraulic power utilizing seawater.

Experience indicates that such equipment functions best when deployed as a system, with active participation by specialists from the well control industry.  Specialists are needed to provide critical knowledge and experience for developing plans and procedures, with identified and engineered interfaces and redundancies. While the proper equipment is required, professional resources can provide the critical difference to ensure a successful resolution of a well control event.

By David Pavel and Brian Grayson, Weatherford

Once drilling is under way, subsurface conditions can be invariably different than what was predicted in pre-drill models, and changes may be required to the plan. Operating with a pressurizable, closed-loop drilling system, MPD can help to identify, for example, pore pressure when the well begins to flow, resulting in enhanced well control.

Managed pressure drilling (MPD) significantly reduces the likelihood of a well control event and associated wellbore problems by addressing two key challenges associated with conventional methods: the uncertainty of the pre-drill model that is the basis for the well design and the inflexibility of the resulting well design and mud regimes.

Operating with a pressurizable, closed-loop drilling (CLD) system, MPD overcomes both of these challenges by enhancing the ability to perform conventional well control methods, providing a dynamic capacity that is counter to static pre-drill models. The result is a significant advance in the well construction process that enhances well control by minimizing the impact of pressure-related events through real-time detection and mitigation techniques.

A good well design is based on a geological/geophysical (G&G) model that is predictive in nature, such as pore pressure/fracture gradient (PP/FG) projections and, when available, offset data. But for all the information and considerable expense that goes into this G&G prediction, it is an educated guess that is limited by its static view of how the well will be drilled.

While the intention is to adhere to the plan, once drilling gets under way, the subsurface conditions are invariably different and require changes to the plan. Those deviations might be as simple as adjustments in the mud weight or as drastic as changing casing setting points.

The ability to counter these variations is constrained by a somewhat ridged well design and the inability to easily make changes to the primary well control elements, such as the BOP, drilling fluid design and kick tolerances, that are designed into the well construction plan.

This typically yields a slow response to wellbore events. For example, when a well experiences an influx, information is often limited to the minimal influx pressure based on mud weight and depth. Standard industry procedure is to close the BOP and observe the wellhead pressure in an effort to characterize the nature of the influx. The well is under control, but drilling is stopped.

The next step is to increase mud weight and circulate the kick out of the hole. This is a slow process that can lead to considerable nonproductive time (NPT) and further wellbore complications.

MPD improves on this well control process by continually gathering actual wellbore data to update the pre-drill model and be able to quickly characterize the influx and manage wellbore pressure. This not only provides a flexible system of prevention and mitigation well in advance of conventional well control methods; it also enables the mitigation of difficult pressure-related wellbore problems that result in NPT.

With MPD, the static model becomes dynamic through a continuous process of updating data and modifying wellbore pressures accordingly. Compared with conventional drilling operations, the process provides engineers with more data of higher quality and delivers it in real time at the wellsite.

In the CLD environment, data is acquired from multiple sources while circulating or with pumps off. Temperature, pressure, flow rate and density measurements are used to calculate mass balance across the wellhead so that any loss or gain in the closed system is immediately quantified. In addition, the system also incorporates standpipe and wellhead pressure and downhole measurements such as PWD, MWD and LWD, if available.

These measurements are used to continually update the model in a dynamic process that provides resolution to what is taking place in the well. Thus, MPD reduces the uncertainty surrounding the pre-drill model by providing actual wellbore data and dynamically managing downhole pressures to allow for the drilling operation to stay within narrow drilling windows.

This certainty about what is occurring downhole makes it possible to differentiate between wellbore pressure variations. For example, the ability to quickly distinguish a gas influx from wellbore breathing can be significant. A misdiagnosis can be extremely problematic. Correct diagnosis not only prevents an event from occurring, it avoids missteps that can exacerbate or initiate a greater problem.

The application of closed-loop systems adds preventive and mitigation barriers to increase the overall integrity of the well. MPD in a closed-loop system provides a flexible response with these barriers that are applied in advance of conventional secondary well control.

MPD provides a flexible response with control and mitigation barriers that are applied in advance of conventional secondary well control.

Proactive control of annular pressure manages wellbore pressure variations, such as those that occur during transitions from pumps-on and pumps-off, preventing potential kicks or losses during connections than can quickly escalate into a well control event. Monitoring and analyzing data on a continuous basis also provides feedback for updating pore pressure predictions on the fly and for modeling future well designs.

If an influx occurs, the system provides mitigation options ahead of changing mud weight or closing the BOP. Detected immediately at only a fraction of a barrel, the influx is immediately countered with a change in downhole pressure achieved by applying annular backpressure via the MPD automated choke manifold at surface. The influx is stopped while it is very small and safely circulated out of the wellbore.

During this entire process, conventional secondary well control capabilities are fully functional. In addition, crew and rig safety are enhanced by the closed-loop configuration that uses a rotating control device (RCD) above the BOP to divert returns away from the rig floor.

The ability of MPD to control and mitigate downhole pressures enhances and supplements conventional well control procedures. As an added layer of well control, these methods can be applied early, effectively and with much less disruption and cost than traditional means.

MPD enables dynamic leak-off and formation integrity tests (LOTs and FITs) to define the boundaries around PP/FG. This provides engineers with accurate numbers at depth and in real time to define the actual drilling window and navigate it by managing the bottomhole pressure.

Having the actual wellbore PP and FG benefit a variety of applications. For example, in a deepwater well in South America, a dynamic LOT was conducted as part of MPD operations. After successfully drilling the well section, the operator wanted to ensure the best possible cement job. To do that, they wanted to know very precisely the equivalent circulating density threshold. The information acquired in a dynamic LOT allowed them to model the cement job to ensure the desired slurry density and rates could be pumped without losses or formation breakdown.

For riser gas handling in deepwater applications, MPD provides a solution to a difficult safety challenge that is generally outside the capabilities of conventional well control methods. MPD monitoring and control provides a means of identifying and controlling gas breakout in the riser above the BOP.

Riser gas occurs as gas entrained in the return flow breaks out of solution. Industry studies suggest that with oil-based fluids, gas influxes entrained in the return mud flow are unlikely to break out of solution until they rise to a level that is just 2,000 ft to 3,000 ft below the drill floor. At this point, the influx is above the subsea BOP and cannot be mitigated conventionally.

The conventional practice for dealing with gas in the riser is to vent it using the rig diverter system. But this approach provides minimal control and involves considerable risk. In a closed-loop system, the gas is quickly detected as it breaks out, and the application of surface backpressure allows it to be controlled and circulated out of the riser. The RCD adds an additional line of safety in diverting the returns away from the rig floor.

Early kick and loss detection and control are fundamental features of an MPD system. In a closed loop, influxes are rapidly detected and characterized to provide drillers with immediate early detection and control.

Speed of action with an MPD system also benefits more subtle but important aspects of the operation. For example, temperature and time affect mud properties that can complicate issues when fighting a kick over a long period of time. Similar issues can also increase the complexity of cementing operations. Using MPD methods, pressure can be applied to offset density losses due to temperature.

In addition to specific pressure control and mitigation capabilities, MPD also provides the ability to manage the process so that pressure-related problems can be drilled through. In the extremes of total loss circulation, MPD methods enable wells to be drilled that are impossible to drill conventionally. Where unconsolidated formations cause instability that can result in sticking, sidetracking and even abandonment, MPD provides the finely balanced control needed to work in these wellbores.

A good example is the drilling of a well off the coast of Ghana, West Africa. Prior efforts in the deepwater province had encountered major problems with an inherently unstable rubble zone and sharp pore-pressure, fracture-gradients changes.

Drilling in the 12 ¼-in.-hole section returned blocky shale cuttings to the surface, indicating changes in wellbore stability and the mechanical stress regime. A rubble zone was identified as the source of the trouble.

The well packed off several times in the zone as shale sloughed around the bottomhole assembly (BHA). Each time, the BHA was pulled up to a more stable section of the wellbore, but despite the efforts, no drilling progress was made. Eventually the main wellbore was plugged and sidetracked.

A higher mud weight was used to drill the sidetrack in an effort to prevent the sloughing. Using the heavier mud resulted in less instability until a significant drilling break was encountered.

Although there had been no indication of high pressure in prior drilling, the well took a 16- to 20-bbl influx. The influx led to shutting in the well, which resulted in the hole packing off again and the BHA becoming stuck. The problems could not be overcome, and ultimately the well was permanently plugged and abandoned.

The Microflux MPD control system successfully mitigated well control and stability issues on a deepwater West Africa well, allowing TD to be reached. MPD provided an additional layer of well control that mitigated a major source of drilling risk and associated nonproductive time. It also provided the ability to mitigate riser gas on the semisubmersible rig.

The next Ghana offset was drilled using an MPD system, which enabled the well to reach the planned depth without borehole stability issues, underreaming or contingency liners.

Accurate detection and control of small influxes in the Ghana well provided the wellbore stability necessary to drill through the trouble zone and reach the planned depth. Annular backpressure maintained stability in the rubble zone by managing ballooning while making connections and by avoiding swabbing when pulling out of the hole. While these conditions are difficult to assess in conventional drilling operations, they are easily identified and mitigated with MPD methods.

The system was instrumental in identifying and controlling small influxes and losses while drilling the 12 ¼-in. and 8 ½-in. sections of the well. Real-time monitoring and control mitigated small oscillations in wellbore pressure before they could escalate into a well control event and provided the means to safely circulate the gas out of the well while drilling.

At the same time, MPD provided a first line of well control ahead of conventional BOP and mud weight management methods. The additional layer of well control mitigated a major source of drilling risk and associated NPT. It also provided the ability to mitigate riser gas on the semisubmersible rig.

Kick simulations were performed to identify the limits of drilling equipment used on the West Africa well, including pressure loadings on the casing shoe, choke line, RCD, riser and BOP. These are key elements of MPD well control, and it is important to ensure that pressure can be safely circulated through them and out of the well through the MPD choke.

Preparations for the project involved transient simulations using the kick module of Dynamic Well Control software. While typically used to simulate different kick situations for conventional drilling, assumptions were made that allowed the software to be used with an MPD system.

A well control matrix was developed to describe a clear course of action based on surface pressure and the volume of the influx. The matrix supports decision-making during critical operations to achieve a rapid well control response. The matrix developed for the West Africa well categorizes the different severities of influx and assigns respective operational procedures to address each possible scenario.

Three operating limits were defined. The normal state has no influx and exhibits surface backpressure of less than 150 psi. In this category, operations may continue without any other action. The second limit is defined by an influx size up to 5 bbl with a surface backpressure limit of less than 800 psi. In this state, drilling stops while the influx is circulated out of the hole. The third limit is reached with an influx greater than 5 bbl and backpressure of more than 800 psi. At this point, drilling operations are suspended and the well shut in using the subsea BOP.

A high degree of planning and organization was important to the successful drilling of the Ghana well. An MPD well control strategy precisely defined and documented the procedure for monitoring and circulating gas out of the well, including riser gas, and a decision tree was developed to identify the severity of influx and the correct operational procedures.

MPD provides a significant advance in the well construction process that enhances the flexibility and effectiveness of well control, while reducing pressure-related wellbore problems. Instead of coping with a pre-drill well model that is static by nature, drillers are provided with a dynamic tool for understanding wellbore pressure in much greater resolution, controlling it with greater efficiency and effectiveness, and adding management capabilities so precise that pressure-related problems are mitigated.

Click here to watch an exclusive video interview with Brian Grayson from the 2012 SPE ATCE  in San Antonio, Texas, on  8 October.

Click here to watch an exclusive video interview with David Pavel and Gavin Humphreys from the 2012 IADC MPD/UBO Conference in March.

Microflux is a trademark of Weatherford.

For completion equipment, Baker Hughes has developed general guidelines for elastomers on what is acceptable for use. The company recommends hydrogenated nitrile elastomers in typical applications, for service up to 50-psi partial pressure up to 250°F, but if the temperature is above that mark, the H2S concentration can only be 10-psi partial pressure.

Industry looks to fit-for-purpose equipment, new guidelines for extreme H2S environments

By Katie Mazerov, contributing editor

Like vinegar in a cylinder of honey, hydrogen sulfide (H₂S) is the industry’s ultimate party-pooper, a sour intruder that puts the damper on an otherwise healthy well that may hold a wealth of hydrocarbons. Better – and perhaps aptly – known as “sour gas,” this naturally occurring but toxic and highly corrosive chemical has always lurked in the oil patch. However, over the years, producers have been able to either manage it in low concentrations or avoid the problem altogether by moving on to other fields.

As global energy demand increases, however, operators can no longer be choosy about which reservoirs to tap, and completing wells with high concentrations of sour gas is a challenge that many companies can no longer avoid.

Sour gas is a condition complicated by high-pressure, high-temperature (HPHT) environments that often exist in areas where oil companies are pushing the boundaries of production – notably ultra-deepwater, where pressures can exceed 20,000 psi. It is produced with oil and natural gas in varying concentrations.

“Because of its corrosive properties and toxicity to humans, operators must be very careful to use properly rated metals and materials in wells with concentrations of H₂S,” said Marco May, senior technical sales manager for Vallourec & Mannesmann, manufacturer of premium Oil Country Tubular Goods (OCTG). Although it is seen in pockets globally, sour gas is prevalent in the Middle East, North Sea, US Gulf of Mexico (GOM) and areas of the former USSR, such as Kazakhstan, he added. Unlike carbon dioxide (CO₂), which has a more long-term effect on materials and is more predictive in determining failure, the effects of sour gas occur much faster, sometimes in a matter of 12 hours.

“No one has come up with a process that reduces or eliminates sour gas, and in low concentrations, H₂S is manageable,” said Peter Fay, packers product line manager for Baker Hughes. “It depends on how corrosion-resistant the metallurgy of the equipment – tubulars and casing – is that is being put downhole. Considerations also must be given to the selection of elastomers for O-rings and packer elements.”

To that end, the industry looks to NACE International. NACE provides education, training and certification for various industries, promotes research of new technology and advocates on behalf of corrosion experts. NACE MR0175/ISO15156 establishes requirements for materials that can be used in H₂S environments in oil and gas production.

“Our mission is protecting people, assets and the environment from the effects of corrosion,” said Linda Goldberg, director of technical activities for NACE. “This has historically been our most widely used standard.” The standard specifies requirements for metal materials that make up the equipment used in sour gas environments, the chemical composition of those materials, the temperatures to which those materials can be heated and other environmental factors that affect the material.

The standard was first published in 1975 and has undergone several revisions. In 2003, it was adopted by the International Organization of Standardization (ISO). The 1975 standard covered only wellhead components. In 1977, the Texas Railroad Commission requested that the industry provide a standard for all oil and gas production equipment exposed to an H₂S environment after an equipment failure caused a fatality.

People can request changes or have materials added to the standard using a ballot process. Ballots approved by NACE are submitted to the ISO for final approval. “Between 2003 and 2009, about 15 ballots were approved and included in the 2009 revision of the standard,” Ms Goldberg said.

There are also two testing standards associated with the primary standard: TM0177-2005, “Laboratory Testing of Metals for Resistance to Sulfide Stress Cracking and Stress Corrosion Cracking in H₂S Environments,” and TM0284-2011, “Valuation of Pipeline and Pressure Vessel Steels for Resistance to Hydrogen-Induced Cracking.”

Failures of wellhead equipment and carbon steel tubular goods during the 1950s prompted action by the industry and NACE to define causes and develop possible remedies. The failures involved 13 Cr martensitic stainless steel wellhead components and carbon steel tubing with strengths greater than 100,000-psi yield strength, explained Robert N. Tuttle, a NACE fellow who was on the committee that developed the 1975 standard. “The failures of susceptible steels were identified as being caused by applied tensile stresses while being exposed to H₂S. Laboratory and field data demonstrated that susceptible steels were those that were of high strength and could be detected by use hardness measurement.”

Through its VAM product line, Vallourec provides Oil Country Tubular Goods for three levels of resistance to sour service environments as defined in NACE MR-0175/ISO15156: Mild Sour (Region 1); Intermediate Sour (Region 2) and Severe Sour (Region 3).

Rockwell C hardness (HRC) measurements were chosen as the method of choice since field hardness testing devices were available. New guidelines limited metal hardness to a maximum hardness of 22 HRC for carbon and low-alloy steels. “Some of the early failures occurred rapidly after exposure to H₂S – often within minutes,” Mr Tuttle said. “The failure mode was later defined as sulfide stress cracking. The failures occurred well below normal equipment design stress.”

NACE participates with organizations like the nonprofit group RPSEA, which is engaged in sour gas research on a number of fronts. “The urgency for dealing with this issue is coming to pass because we are going into HPHT regimes in places like the Lower Tertiary of the GOM,” said James Pappas, vice president of RPSEA’s ultra-deepwater program. “The preference is to have a solution in hand before it’s really necessary and avoid making costly mistakes.”

First to consider is the magnitude of the problem, he said. “The empirical equations used to estimate damage from HPHT in a sour environment are inadequate in many cases. We’re having to extrapolate the damage assessment from information we have from laboratory testing.”

RPSEA is launching a project to examine sour environments at various combinations of 350°F and 400°F and pressures ranging from 20,000 psi to 30,000 psi to try and verify the data and, more importantly, to establish new equations.“These new equations can be plugged into models to better forecast what is happening in sour environments and ultimately determine what the best metals are and see if any new alloys need to be created. We know corrosion inhibitors work because we’ve tested them at lower temperatures and pressures. We may need to create new inhibitors at these higher temperatures and pressures, but we won’t know that until we do the analysis.”

RPSEA is also studying the fatigue limits of deepwater risers in H₂S environments. Lab tests put riser materials under different stresses to determine breaking points and understand what happens from a chemical side. “The next step is to verify the lab results by conducting a field test in which we introduce H₂S to actual risers hanging off a platform but not hooked to a well,” he said.

For completion equipment, Baker Hughes has developed general guidelines for elastomers, Mr Fay explained. “It depends on the concentration of sour gas and the temperature of the well, because the higher the temperature, the more susceptible both the metals and elastomer materials are to the effects of H₂S. For example, nitrile rubber can be used safely in wells with a low concentration of sour gas, but once the temperature goes above 175° F, standard nitrile is no longer acceptable.”

For typical applications, Baker Hughes recommends hydrogenated nitrile elastomers for service up to 50-psi partial pressure up to 250°F, but if the temperature is above that mark, the H₂S concentration can only be 10-psi partial pressure. “When we start using more premium elastomers, the standard guidelines switch from partial pressure measurements to percentages of fluid,” Mr Fay added.

Specifications also pertain to an occurrence known as hydrogen embrittlement, where high levels of sour gas cause equipment to crack or break, even in cases where corrosion is not a problem. “For low-end completions, many of our customers will use a carbon steel alloy, but that has limits on the hardness of the material,” he continued. “In those cases, the sour gas concentration is relatively low and corrosion is not a concern, but hydrogen embrittlement can still occur. In situations with a higher concentration of H₂S, operators will choose a 13-chrome (corrosion-resistant) base material. For highly corrosive applications, Inconel is the product of choice.”

The industry has known solutions within a certain boundary of temperatures, and new research is looking at solutions for either higher concentrations of sour gas or higher temperatures. “Once we get outside the box defined by NACE, we’re facing a huge research and development project to develop materials that will meet the standards we strive for,” Mr Fay noted.

“For example, with GOM Lower Tertiary deepwater platforms, we’re typically talking about higher temperatures and pressures, so if sour gas is present in those environments, we are pushing the boundaries of where we haven’t been before. NACE only covers metallurgies up to 450°F, so if we have a sour gas completion that exceeds 450°, we have to do our own metallurgical evaluation of the properties and materials under those conditions because there are no published standards.”

Research is advanced by the major service companies, which have an interest in ensuring the materials can perform. “We are constantly developing HPHT technology to try and push the boundaries,” he said. “We offer many types and models of HPHT equipment – packers, safety valves, liner hangers – and they could all see service in H₂S applications.”

Sour gas is also problematic in high-pressure wells, where there are currently not a lot of accepted industry equipment grades especially when the concentration of H₂S is high. “If we have higher pressures, such as 20,000 psi and above, even small amounts of sour gas are a problem,” Mr May said.  While stronger steel and casing are required to handle depths and high pressure, a more malleable or ductile steel is necessary to withstand the sour gas conditions. “Depending on how deep you drill, the tubulars require a certain tensile strength, collapse behavior and burst pressures that require higher-strength steel.

“But, those products are not acceptable by NACE for use in sour gas environments because they are susceptible to hydrogen embrittlement,” he continued. “Lower-strength steel prevents that issue but isn’t strong enough to meet the pressure.” For example, Vallourec’s VM-125 SS (sour service) is a high-strength steel that has been used for HPHT environments in the GOM with slightly sour conditions, but it is not rated for the most severe level of H₂S as defined by NACE. Addressing that conundrum will require a two-step process, Mr May believes. “We need to develop stronger steels that aren’t susceptible to this type of hydrogen embrittlement, and we need to design heavier-wall casing that still meets all the properties through the wall thickness.”

Through its VAM product line, Vallourec provides OCTG for three levels of resistance to sour service environments as defined in NACE MR-0175/ISO15156: Mild Sour (Region 1); Intermediate Sour (Region 2) and Severe Sour (Region 3).

For extreme environments, the solution is to develop fit-for-purpose equipment. “For completions that encounter CO₂, in addition to H₂S, the choice will be a high-quality alloy for the tubing, such as high-grade nickel, rather than carbon steel,” Mr May said. “We are seeing increasing demand for fit-for-purpose equipment as more and more operators are conducting well testing to better understand the conditions and determine if they need full-scale sour gas equipment.”

Inconel is a registered term of Special Metals Corporation.

VAM is a registered term of Vallourec & Mannesmann.

BSEE, industry discuss BOP rules

Following an August meeting with James Watson, director of the US Bureau of Safety and Environmental Enforcement (BSEE), IADC, API, NOIA and the Offshore Operators Committee have sent a letter to the director reiterating industry concerns with possible requirements being included in upcoming proposed rules on BOPs.

During the meeting, BSEE had indicated that the agency was evaluating different and/or supplemental requirements for BOPs in addition to the requirements in the draft fourth edition of API Standard 53 (S53) even though S53 was in line with what BSEE was seeking.

The industry discussed how it had to work through the current rig fleet, the newbuild rigs and future technology developments in drafting S53 and utilized the process to solicit and address comments from industry. Plans are to release S53 in Q4 2012, and BSEE has stressed the need to publish S53 as soon as possible in order to align with the time frame of the rulemaking process for the new BOP rule.

Industry also explained its concerns around specific requirements related to pipe rams and shearing capability. Of particular concern is the potential requirement for much longer space-out between shear rams, which would significantly impact the existing floating rig fleet. With the large number of new rigs under construction, significant new requirements could necessitate extensive modifications with cost and schedule impact, industry stated.

Industry also maintained that the focus should remain on well control rather than shearing. Shearing the pipe is a last resort, and all effort should be made to maintain communication with the bottom of the well to control pressure instead. The industry wondered if well control scenarios and practices are being fully considered by BSEE while the agency drafts the new rules and highlighted the potential unintended consequences if the rulemaking process solely focused on the BOP emergency functionality.

The industry further expressed the need to address risk assessment in future rulemaking and provided an explanation about risk assessment requirements included in S53.

In response to BSEE’s stated interest in life cycle analysis of critical equipment, the industry discussed efforts to develop a new document, API 16AR, which would address repair and re-manufacturing of well control equipment.

Additionally, BSEE asked about industry investment in next-generation well control equipment and confirmed the proposed BOP rule addresses shear capability, automation and enhanced sensors. Industry comments are:

• Shear capability: Industry is strongly concerned about the focus on “shear certain” and believes greater focus should be placed on maintaining primary well control. The drive toward “shear certain” also can add significant complexity to an already sophisticated system, which in turn adds risks.

• Automation: Automating the entire well control process would be an incredibly difficult task given the uncertain and changing subsurface pressures, fluids, rock strengths, etc. Careful consideration must be made as to the level of automation being requested.

• Enhanced sensors: Manufacturers are already developing ram position indicators to monitor the “health” of subsea well control systems. Further research is needed to provide additional capabilities such as flow measurements as mentioned by BSEE and others.

Sen. David Vitter, R-La., sent a letter to BSEE director James Watson in October 2012 indicating his concern with BSEE’s interim policy document on “Issuance of an Incident of Non Compliance (INC) to Contractors (IDP No. 12-07).”

Sen. Vitter stated that he is concerned with the expansion of BSEE’s current regulatory authority to include contractors. He also requested “adequate information justifying this policy, including the agency’s internal legal analysis,” as a means of transparency.

“The guidelines put forward by BSEE in IDP No. 12-07 are still non-specific to their intent and open ended in their application,” Sen. Vitter wrote. “As a result, the offshore service industry is in a quandary as to what liability for contractors will be in the future and what their vulnerability will be to agency actions.”

The senator also said that the offshore industry feels this policy “is a major, unprecedented departure from past practices on the US Outer Continental Shelf.”

Sen. Vitter suggested BSEE initiate a formal rulemaking process to promote transparency and allow all stakeholders the chance to provide their input before the agency enforces such a policy.

The revised MARPOL Annex V on “Prevention of Pollution by Garbage from Ships” enters into force on 1 January 2013. The convention is applicable to MODUs.  The revised regulations include a prohibition on the discharge to the sea of any garbage except in accordance with express conditions established by the regulation, institute a  requirement for a ship-specific garbage management plan, including procedures for waste minimization and training, require posting of warning placards, and revise the requirements to maintain records of garbage discharge and transfer.

The new edition of the IADC’s semi-annual report “International Standards Activities Affecting the Offshore Oil and Gas Industries” is available online at www.iadc.org/iadc-committees/iadc-
offshore-operating-division/offshore-reporting/. This report provides a reference to standards development activities of various organizations with the potential to affect offshore oil and gas operations e.g., the International Maritime Organization, International Labour Organization, the International Organization for Standardization and various international trade associations.

This latest edition includes information on the International Maritime Labour Convention, MARPOL Annexes V (Garbage) and VI (Air Pollution), the Ballast Water Management Convention, MODU Code amendments for confined space entry rescue drills, new IMO requirements for lifting appliances and newly issued ISO standards on conformity assessment, quality management  and site assessment for jackups.

IADC has launched an initiative for a comprehensive revision and update of the definitive rig-operations manual, the IADC Drilling Manual. The end-to-end revision aims not only to update existing chapters but also incorporate information on new technologies and industry best practices.

As envisioned, the 12th edition will be published both in print as well as electronically, featuring color graphics, videos and animations.

The effort is being undertaken by the IADC Communications Department under the leadership of group vice president/publisher Mike Killalea.

“The update of this important industry resource will provide the industry with better materials that will catalyze improved performance at the rig site and the operations office,” Mr Killalea said. “In addition, we intend to maintain the IADC Drilling Manual as an evergreen resource, with regular updates by an informed group of technical experts.”

Fran Kennedy-Ellis, who recently joined IADC as director – publishing initiatives, will serve as project leader for the initiative. Ms Kennedy-Ellis is organizing a steering committee to shape the work ahead.

Subject-matter experts are needed to contribute on all aspects of drilling operations. Further, young professionals are encouraged to participate.

Thanks to the following companies and university that have already committed their support: ConocoPhillips, Halliburton, Marathon, National Oilwell Varco, Precision Drilling, Weatherford and Texas A&M.

A kick-off meeting will be held on 28 November at IADC’s office in Houston.

For more information or to get involved with the project, contact Ms Kennedy-Ellis at +1/713-600-1887 (fran.kennedyellis@iadc.org).

Scott Maddox joins IADC

Scott Maddox has joined IADC as director of the drilling & well services division, providing operational and technical support to the IADC Underbalanced Operations & Managed Pressure Drilling, Advanced Rig Technology and Well Servicing committees. He will also assist in assembling the technical content of IADC conferences and workshops.

Mr Maddox was most recently QHSE manager for the US unit of i-Tec Well Solutions. Previously he was corporate HSE manager for Xtreme Coil Drilling. Prior to that, he held HSE-related positions for Noble Drilling and Grey Wolf Drilling.

Mr Maddox was also previously a firefighting instructor for the US Navy. He is a graduate of Columbia Southern University and is currently enrolled in the MBA program at Grantham University.

Mr Maddox can be reached at scott.maddox@iadc.org.

IADC holds Subsea BOP Workshop

IADC held a Subsea BOP Workshop on 30 October in Stavanger, Norway. The event, organized under the auspices of the IADC Future Technology Subcommittee (FTS), sought to identify BOP-related problem areas for operators, drilling contractors and OEMs and foster discussion among BOP technology developers and users.

FTS vice chairman Dustin Torkay, Seadrill Americas, provided welcoming remarks. Presentations from Helge Ørgersen, Statoil; Per Wullf, Seadrill Management; David Dietz, GE Oil & Gas; and Mel Whitby, Cameron Drilling Systems covered explosive shearing, electric BOP controls and BOP monitoring.

IADC attends Oil & Gas Denmark launch

At the launch of Oil and Gas Denmark on 23 August, the Danish Minister of Energy, Martin Lidegaard (front, left), spoke about the importance of the Danish oil and gas industry. The new
association is headed by Martin Næsby (front, right).

Jens Hoffmark, IADC regional VP – European operations, attended the 23 August launch of Oil and Gas Denmark, an industry association that represents Danish drilling contractors, oil companies and service companies. The new group, headed by managing director Martin Næsby, has four focus areas: development of the oil and gas sector, infrastructure, HSE and development of competency. In attendance at the launch event was Martin Lidegaard, Danish minister of energy. His inauguration speech emphasized the importance of the Danish oil and gas industry, which contributes about 9% of the total Danish export. Denmark has been self-sufficient in oil and gas since 1991 and has been a net exporter of energy. In the next five years, US $8 billion is expected to be invested in exploration and development. For more information, please contact Mr Hoffmark at jens.hoffmark@iadc.org.

Fran Kennedy-Ellis joins IADC as director of publishing initiatives

Fran Kennedy-Ellis has joined IADC as director – publishing initiatives. Ms Kennedy-Ellis will oversee the update of the IADC Drilling Manual, among other projects. Her duties will include author relations, content development, digital asset management, and permissions and copyright issues for print and electronic editions. In this role, she will organize a steering committee and work groups to revise existing chapters and write new ones, develop workshops to support IADC publishing initiatives and attend strategic IADC events to support the revision effort.

“Fran brings to IADC significant experience in revamping publications and enormous energy that will significantly benefit our members and our association,” Mike Killalea, group vice president/publisher of IADC, remarked. ”

Ms Kennedy-Ellis previously served as technical publications manager for the Petroleum Extension Service (PETEX) at the University of Texas at Austin. She earlier worked at SPE, overseeing its book program, technical journals, peer review and publications committees. She has a bachelor’s degree in English and a master’s in Administration from Texas Tech University.

Ms Kennedy-Ellis can be reached at fran.kennedyellis@iadc.org.

By Katherine Scott, editorial coordinator

A Newfield Exploration reservoir engineer stands in front of H&P FlexRig 389, operating in the Eagle Ford, where Newfield is drilling its first 10,000-ft lateral. The company says it is averaging 11,000-ft laterals in North Dakota’s Williston Basin. Image courtesy of Newfield Exploration

Trumpets or fireworks may be absent in celebrating substantial industry growth as 2012 concludes, but that’s no matter. Over the past 12 months, industry solidified its footing after facing significant regulatory and economical challenges over the previous couple of years. And although industry is ending the year with a slowdown  in available rig work, strong oil prices remain a welcome sign for a positive outlook for 2013.

“Right now we’ve gone down in rig utilization. There’s no doubt. The numbers substantiate that for the whole industry,” John Cromling, executive vice president for Unit Drilling, said. “But I think it’s a short-lived downturn, and I think 2013 is going to be good.”

Earlier this year, Drilling Contractor reported in its March/April issue of high rig utilization, rising dayrates and a general market boom in US land drilling. Since then, however, the market has lost some steam. Operators reevaluated budgets against natural gas prices and seemingly softening oil prices, and the call for drilling rigs weakened. As a result, contractors have seen their business slow and expect it to stay that way through the end of the calendar year.

“In the late June time frame, WTI oil prices dipped just very briefly below $80 a barrel. That was a bit of a wakeup call for everybody. Budgets were scrutinized  and operators recognized that if they maintained current rig activity, they were going to outspend their budget, so some rigs were released,” John Lindsay, president and COO of Helmerich & Payne, said.

The transition from dry gas plays to liquids-rich in the US endured, however. Growth potential in key areas such as the Eagle Ford, the Permian Basin and emerging plays like Ohio’s Utica Basin have garnered a confident picture of 2013.

“There’s a huge disparity between oil and gas prices, and our view is that we’ll be in a lower gas price world for longer,” Stephen Campbell, vice president of investor relations for Newfield Exploration, said. “For next year, I see a continuation of the same theme where all the money is going into oil and liquids-rich plays.”

However, amid a general optimistic attitude for 2013, an industrywide feeling of uncertainty remains – uncertainty in the global economy, uncertainty in global and regional politics, and uncertainty in the global market. Although oil prices remain relatively high at about US $85/bbl to $95/bbl, natural gas prices continue to hover around $3/mcf to $3.50/mcf, causing some to wonder if such continued weak pricing may lead to a repeat of the 2008 downturn.

Helmerich & Payne, Unit Drilling, Trinidad Drilling, Pioneer Natural Resources and Newfield Exploration capture their experiences of 2012 and general outlook for 2013.

H&P FlexRig 500, a FlexRig5, operates in the Marcellus. The H&P fleet, supported by its advanced-technology FlexRigs, currently has approximately 236 of its 285 US drilling units in operation; the rigs are predominately 1,500-hp, AC-drive rigs that typically target a range of 14,000- to 22,000-ft drilling depths.

In 2012, the migration that began more than a year ago from the drier gas basins to liquids-rich plays in the US continued, with some companies moving operations completely to basins and plays such as the Permian and the Bakken. Within that shift, however, is emerging a sub-trend toward higher-quality liquids.

“When we say ‘liquids-rich,’ it may range from a low percentage of liquids in one part of the basin to a high percentage of liquids in another part of the basin,” Mr Lindsay said. “What we’ve started seeing now are rigs transitioning from the lower end of the natural gas liquids to black oil basins or higher-quality oil and liquids. Customers are looking to target the commodity that’s going to bring them the highest prices per barrel.”

Customers also are looking for the highly efficient AC-drive rigs, he said. H&P estimates that there were approximately 1,750 land rigs working in the US as of late September, and only 30% are AC-drive rigs, compared with 31% SCR and 39% mechanical rigs. “Many of the rigs that are available are not the rigs that customers want,” Mr Lindsay said. “We continue to see this sideways to slightly down transitioning of the rig count because customers are high-grading their rig fleets. Some of the older, less efficient, less safe rigs are continuing to stack, and this replacement is not a ‘one for one’ trade.”

When asked about the outlook for 2013, he added: “At the first of the year, if the WTI oil price remains in the $80/bbl to $95/bbl range, then activity should improve, and the best rigs, the AC rigs, are going to be snatched up first. … Those rigs should also be able to continue to command a performance premium in the marketplace, assuming the commodity prices hold.”

The H&P fleet, supported by its advanced-technology FlexRigs, has approximately 236 of its 285 US drilling units in operation; the rigs are predominately 1,500-hp, AC-drive rigs that typically target a range of 14,000- to 22,000-ft drilling depths. The Eagle Ford is the most active basin for the company, where approximately 90 of the company’s rigs are employed and where Mr Lindsay predicts another strong market in the coming year.

Three FlexRig3s work in Oklahoma.

The company also has 17 newbuilds under way that will be delivered at a pace of about four rigs a month until the end of 2012, followed by four rigs to be delivered in Q1 2013. All will be AC-drive FlexRigs built against term contracts of three to five years. Twelve rigs are going to the Eagle Ford shale, three will be sent to the Permian Basin, one is going to the Fayetteville shale and one will go to the Bakken. Outside the US, H&P also has 16 FlexRigs operating across Colombia, Argentina, Bahrain, Abu Dhabi and Tunisia.

Looking toward the industry’s growth potential in 2013, Mr Lindsay commented that marketplace uncertainty is likely to remain a lingering concern and may impact drilling budgets. “Companies are going to be less likely to invest and have more aggressive drilling budgets. A global economic slowdown is going to reduce the demand for oil and gas products, which is going to have a negative influence on price. In turn, that’s going to decrease the number of wells drilled,” he said. Still, he urged, the industry can’t simply stop spending money. “You’ve got to be prepared to spend through the ups and downs. Downturns are opportunities for companies to prepare for the next up cycle.”

Of all US onshore wells being drilled, it’s believed that approximately three-fourths are now horizontal. It’s therefore no surprise that Unit Drilling has seen a high 85% utilization rate of its 1,000- to 1,700-hp rigs, which are typically best suited for horizontal wells. “That’s what is the most popular by far,” Mr Cromling said. And, yet, he points out that the classification of rigs by horsepower is “almost a meaningless number anymore with horizontal drilling.” Mr Cromling believes that with the right mud pumps, top drive and pit system, the rig’s horsepower rating can become insignificant because “the pit system and pumps are key to

Above and left: Unit Drilling’s Rig 201 is currently drilling in Cameron Parish, La., for Chevron. Unit Drilling has seen a high 85% utilization rate for its 1,000- to 1,700-hp rigs, which are typically best suited for horizontal wells. “That’s what is the most popular by far,” said John Cromling, Unit’s executive VP, although he believes that with the right mud pumps, top drive and pit system, the rig’s horsepower rating can become insignificant. Images courtesy of Unit Drilling.

how you drill a horizontal well.”

Lower-horsepower rigs, in the range of 700 hp to 900 hp, are beginning to find increased use in emerging marketplaces, he continued. Recent finds in the Mississippian play in north Oklahoma and southern Kansas, in particular, have increased the drilling of shallow horizontal wells. “This trend toward shallower horizontal wells really hasn’t even reached its full potential,” Mr Cromling said. “Who knows how many more of these shallow plays there could be? There’s a lot of old producing areas that have not been drilled horizontally that lend themselves to be good candidates.”

He believes that, due to the size of the geological area of the finds, the shallow horizontal drilling trend could last for the next decade. “You’re not talking about a little pod somewhere. You’re talking about hundreds and hundreds of square miles of geographic area, so your potential for a high number of wells is great.”

To drill these massive numbers of horizontal wells, contractors have honed in on high-specification rigs, pushing industrywide drilling efficiency to the best it’s ever been, Mr Cromling believes. In turn, this means that fewer rigs are needed to drill the same footage.

This year alone, Unit upgraded and refurbished 10 rigs with top drives, more horsepower and new pumps. “If we hadn’t refurbished those rigs, they probably wouldn’t be working. That’s how critical it is,” Mr Cromling said. Going forward, he believes horizontal drilling will continue to drive a large number of additional pump and mud system upgrades.

Similarly, upgrading their rig fleet to bi-fuel systems, Unit has expanded the efficiency of its rigs by allowing them to predominately run on natural gas when available and practical. “Using natural gas today is the best fuel you can use; it’s the cheapest, the cleanest and the most available.”

Above and left, top: Unit Drilling’s Rig 201 is currently drilling in Cameron Parish, La., for Chevron. Left, middle and bottom: Unit’s Rig 322 is operating in Sublette County, Wyo., for QEP. New areas of activity continue to pop up in the US, Unit executive vice president John Cromling said. However, instead of creating whole new marketplaces for rigs, operators are more often choosing to move rigs from one play to another. Images courtesy of Unit Drilling.

Still, although upgrading rigs can support higher rig utilization numbers for contractors, overall contract length and dayrates have come down for the industry, Mr Cromling said, adding that it’s primarily newbuild rigs that are securing long-term contracts these days. Because the current marketplace is weak, operators have their choice of rigs. “If they don’t have to make a long-term commitment to get a rig, then they’re not going to,” he said. “The market needs to pick up a lot in 2013 to where operators feel like prices are trending upward. Then they’ll be receptive to locking in for a longer time period.” And with the downward trend in activity, dayrates too have followed, he said. “It’s just a fact of life.”

New areas of activity do continue to pop up in the US, Mr Cromling said, such as Ohio’s Utica play. However, instead of creating a whole new marketplace for rigs, operators tend to move rigs from one play to another, such as from the Marcellus to the Utica. “The Permian’s still hot, the Eagle Ford’s still hot, but it’s not adding a greater number of rigs. They just move from one place to another, which is not bad, but it’s not as exciting as if we’d gone from 2,000 rigs to 2,500 rigs,” he said.

Unit is most active in the Bakken, the Mississippian play, western Oklahoma and the Texas Panhandle, with 127 US land rigs that are being operated at 56% utilization. The company also added three 1,500-hp newbuilds this year. One deployed in May to North Dakota on a three-year contract with Kodiak while the other two were delivered in January and May for a three-year contract with QEP in Wyoming.

Trinidad Drilling’s Rig 138 (above) and Rig 137 (left, top) operate in the Eagle Ford, where the company has the highest concentration of its North American land rigs, at 20 units. Left, middle: Trinidad’s Rigs 56 and 57 were constructed at the company’s manufacturing facility in Nisku, Canada. Rig 56 is now working in British Columbia, and Rig 57 is operating in oil sands south of Fort McMurray. Left, bottom: Trinidad Rigs 48 and 50 conduct pad drilling in northeastern British Columbia. The contractor says Canada has taken advantage of the pullback in US rig demand to push for more rig performance. Images courtesy of Trinidad Drilling.

For Trinidad Drilling, one of the biggest lessons learned from the 2008 downturn was the benefits of take-or-pay contracts, “where a rig is contracted, generally a newly constructed built-for-purpose style rig, for a guaranteed number of days per year at a set dayrate based on the total number of years they’re willing to commit to the rig,” Lyle Whitmarsh, CEO of Trinidad Drilling, said. In the fickle drilling market, contractors like Trinidad have increasingly sought out these types of contracts to guarantee returns on investment for newbuild rigs.

“Because we have take-or-pay style contracts, we’re not having to react to short-term spikes,” Mr Whitmarsh said. “Our rigs are continually working; 60% of our fleet is on long-term contract.”

Still, although term contracts are helping Trinidad to manage the spikes and valleys of commodity prices swings, Mr Whitmarsh acknowledges that these ups and downs will continue to challenge his company as well as the overall industry over the coming year. A firm market rebound in 2013 will be directly dependent on stability in commodity pricing, he believes.

Besides leveraging take-or-pay contracts, Trinidad also has designed its fleet to be able to move between a number of plays and react quickly to shifts in operator budgets. “As we move into 2013, we want to be able to respond and assist our customers when the global economy puts pressure on their operations,” Mr Whitmarsh said. Of its total fleet of 129 land drilling rigs in the United States, Canada and Mexico, approximately 85% to 90% are drilling for oil or liquids-rich natural gas, and the highest number of them are in the Eagle Ford, with 20 rigs.

“It would take a fairly fundamental shift in gas commodity pricing to see an incremental number of drilling rigs move back to the gas side,” he said.

In 2012, Trinidad constructed four newbuilds, all built-for-purpose, AC-drive rigs ranging from 1,000-hp to 1,500-hp for Canadian operations. Mr Whitmarsh explained that Canada, in particular, has taken advantage of the pullback in US rig demand to push for more performance up north. “There seems to be more openness in Canada at this time for certain style of rigs. They’re getting themselves in a position where they can contract a newer-style rig to start capitalizing on their efficiencies.”

Trinidad also added a rig in April of this year to their Canadian operations where it is working in the oil sands near Fort McMurray in Alberta, drilling steam-assisted gravity drainage wells. The rig was designed in-house and built using a new moving system that allows the whole rig to move as a unit, Mr Whitmarsh said. In the past, rigs would get so far before trucks needed to be brought in to move the associated buildings, he said. Now the rig is limited only by the availability of solid, level ground on which to move the rig. “We have received expressions of interest from a number of customers for similar-style rigs to be used in both oil sands and other applications, including the Bakken.”

For 2013, Mr Whitmarsh also sees sustained interest in building new equipment, although the number of inquiries is at a lower level than 12 months ago. In particular, Trinidad sees opportunities for growth onshore Mexico, where the company currently has three rigs operating. “That was off a high for us at seven rigs, so we’d like to add more rigs back in, either in the form of a newbuild, or it could be done in an upgrade,” Mr Whitmarsh said. “Overall, we believe there are still pockets in Mexico and North America that will allow Trinidad and the industry to add assets throughout 2013.”

Pioneer further expanded its vertical integration activities in 2012 and believes it is now the 13th-largest pressure-pumping company in North America. “We’ve got over 300,000 horsepower of equipment, with most of it employed in the Spraberry and Eagle Ford areas,” Steve Mamerow, VP – corporate drilling and completions for Pioneer, said. After divesting all non-US assets, Pioneer has returned to being solely a US land company. Images courtesy of Pioneer Natural Resources.

When it comes to E&P investment, Pioneer Natural Resources believes it’s best to drill what you know. The company recently sold the last of its non-US assets in order to concentrate efforts back into familiar terrain. Previously, Pioneer had drilling activity in places like South Africa, Argentina, Tunisia, Canada, Gabon, offshore Nigeria and offshore Gulf of Mexico but is now solely a US land company. “We went into deepwater and international exploration to try and grow the company because of perceived maturity in the US at the time, but since last year we have been returning to our roots,” Steve Mamerow, vice president – corporate drilling and completions for Pioneer, said.

Pioneer made the Eagle Ford, the Permian Basin, where it predominately operates in the Spraberry and Wolfcamp plays, and Alaska its focus areas for drilling in 2012. In the Eagle Ford, Pioneer is currently running 12 rigs and had up to 44 rigs working in the Permian Basin during 2012. The company has one rig in Alaska operating off of Oooguruk Island and earlier this year during the winter drilling season employed a second rig to target additional formations.

“One well we drilled turned out to be a nice discovery in a shallower horizontal well, so we we’re going to be doing additional appraisal work on that prospect this winter,” Mr Mamerow said. Both rigs were contracted from Nabors. Rig 19AC has been under contract for three years, which Pioneer recently extended for an additional two years plus two optional years. The second rig, 27E, is contracted to drill for 120 days this winter.

For 2013, Pioneer plans to retain the same focus areas as it continues to emphasize oil assets. “Where we are drilling now is where we are likely to spend the bulk of our capital in 2013 and beyond,” he said. “We expect to focus most of our capital spending in 2013 in the Permian Basin and the Eagle Ford, where we are able to deliver superior returns.”

As much of the industry has, healthy oil prices relative to weaker natural gas pricing has driven Pioneer to place a majority of its operations in the liquids-rich areas of the US for 2012. “Our objective is to spend within our cash flow,” Mr Mamerow said. “With current oil prices, our mix of liquids to gas has been a strong impetus for us to continue to focus our efforts on places where there are a lot of liquids.”

Fueled by strong returns and the desire to enhance the execution of its drilling program, Pioneer further expanded its vertical integration activities in 2012.

“We’re now basically the 13th-largest pressure-pumping company in North America. We’ve got over 300,000 horsepower of equipment, with most of it employed in the Spraberry and Eagle Ford areas,” Mr Mamerow said. The company also has 15 drilling rigs in the Permian Basin and other service equipment, such as pulling units, frac tanks, hot oilers and water trucks.

A Newfield-operated rig works in the Eagle Ford. Liquids-rich plays like the Eagle Ford continue to attract operator budgets. Newfield, for example, has not drilled a gas well in more than a year. Image courtesy of Newfield Exploration.

As horizontal drilling expands, operators are pushing lateral lengths out longer and longer with innovations in casing design,    built-for-purpose rigs and higher ROPs. Newfield Exploration, for example, is averaging 11,000-ft laterals in North Dakota’s Williston Basin and drilling its first 10,000-ft lateral  in the Eagle Ford. “That’s not just a Newfield success story; that’s an industry success story,” Mr Campbell said. “With the success of these extended laterals, you will continue to see the lateral length get pushed longer and longer. … Our industry is able to drill the same amount of hole each year with less rigs.”

For example, in 2010, Newfield averaged 45 days from spud-to-rig release in the Williston Basin. They improved that number to 35 days in 2011, but today are “routinely getting wells down in 21 days,” Mr Campbell said. “We’re able to drill more hole per rig with higher ROPs from the same rig fleet than we could a year or two ago.”

Falling in line with the industrywide move to liquids-rich plays, Newfield has not drilled a gas well in more than a year, Mr Campbell added. “We have completely stopped investing in dry gas plays. … You’d have to see a dramatic increase in gas price, as well as a dramatic drop in oil price, to make gas investments competitive again.”

Since August 2004, the company has invested heavily in Utah’s Uinta Basin, where they are running seven rigs with an estimated activity this year of approximately 300 wells. Newfield has referenced at least 6,000 potential drilling locations in the Uinta Basin over a decade-long period of activity. “The Uinta Basin  has the deepest inventory of wells to drill over the next decade,” Mr Campbell said. “We allocated $550 million of our 2012 budget into Utah. It’s our largest oil asset in terms of reserves and production.”

Besides the Uinta Basin, Newfield’s focus areas for 2012 included the Mid-Continent’s Cana Woodford play, where the company allocated $300 million to a six-rig program, and the Williston Basin, where Newfield allocated $250 million to a three-rig program. Mr Campbell looks for these to remain large focus areas into 2013.

Newfield also has operations in Malaysia and China but holds its core assets on US land, recently selling its offshore Gulf of Mexico acreage and clarifying its role as an onshore US producer. “We’re producing a record 31,000 to 32,000 bbl/day in Malaysia, but I would not look for us to add additional areas in the international arena. Our plate is pretty full today with the existing inventory we have in the US,” Mr Campbell said.

On the regulatory side, Mr Campbell notes that challenges remain on the state and federal levels. It can take Newfield upwards of nine months to get a permit to drill a well in Utah, where they operate on federally owned land, he said. “From an efficiency standpoint, if you start and stop a drilling program, you lose efficiencies with your crews and your rigs, and that’s critical in our operations.

“There needs to be lots of preplanning and an open dialogue with those federal agencies to ensure that they understand our needs going forward and we also understand their constraints in issuing permits so we can balance that out,” he said.

Looking back on 2012, Mr Campbell stressed the improvements industry has made in reversing a decades-long decline in oil in the US. “The Williston and the Eagle Ford are two plays that are really driving that reversal of a 30-year decline in the US,” he said. “And both of those basins still have significant growth in 2013 based on the activity and inventory of uncompleted wells today.”

More importantly, the reversal has stimulated the US economy. “For the first time, we’ve made a meaningful impact in the amount of oil that’s imported into the US everyday,” he said. “Nine percent of the jobs created over the last year were created in energy, so our energy business is making an impact on the broader economy by exploiting resources in the US today. We’re removing the roadblocks to growth.”

2012 industry snapshot by the numbers

• Helmerich & Payne is most active in the Eagle Ford, where it has approximately 90 rigs employed. H&P also has 17 newbuilds under way.
• Unit Drilling upgraded and refurbished 10 rigs this year. Of Unit’s fleet, 1,000- to 1,700-hp rigs have an 85% utilization rate.
• Approximately 85% to 90% of Trinidad’s land rigs are drilling for oil or liquids-rich natural gas. 60% of the fleet is on long-term contracts.
• Pioneer is the 13th-largest pressure-pumping company in North America, with more than 300,000 horsepower of fracturing equipment.
• Newfield is averaging 11,000-ft laterals in the Williston Basin and drilling its first 10,000-ft lateral in the Eagle Ford. The company has also reduced its average spud-to-rig release in the Williston Basin from 45 days in 2010 to 21 days in 2012.

By Katie Mazerov, contributing editor

When National Oilwell Varco (NOV) unveils its open-platform drilling automation system NOVA in 2014, it could be the step-change to autonomous drilling that will alter the future of hydrocarbon recovery.

Development of the system is marking a shift from product-thinking to process-thinking, a transition that must occur for the industry to move forward, says Hege Kverneland, vice president and chief technology officer for NOV. “We need to look much more at the process of drilling a hole in the ground more efficiently – better, faster and safer,” Ms Kverneland said.

Built in 2009, the MAERSK DEVELOPER, a semisubmersible working for Statoil in the US Gulf of Mexico, is one of the most advanced rigs in Maersk’s fleet. The company’s latest generation of rigs includes more machines that can be operated in one sequence without human interface, keeping workers out of harm’s way on the drill floor and in control from the driller’s cabin

“Most of the new product development will be focused on the well and well safety, and the drilling process related to that, by making equipment like robots and taking humans out of the middle.”

Major service companies also continue to be leaders of innovation, particularly in the development of downhole tools. Foremost among those are data delivery technologies. But with the tremendous amount of data to process, many believe the focus now should be on ways to more meaningfully process the data.

“Data is important, but even more important is taking that data and turning it into useful information that enhances the quality of the decisions being made and to provide a holistic view of rig operations and the health of the well,” said Mark Mitchell, vice president, drilling optimization for Weatherford.

In an age of hard-to-extract, tight oil and gas reserves, new attitudes about technology development are moving the industry to the next generation, powering the boom in unconventional oil and gas production, exploration of new frontiers in ultra-deepwaters and ventures into extreme environments that were previously out of reach. Most agree that new technology must have the right stuff to make it in this high-stakes business – that is, bring value by reducing risk, enhancing safety and delivering greater efficiency.

The push is coming from inside the industry and out – large independent and major oil companies, forward-thinking national oil companies, major service providers, drilling contractors, equipment manufacturers and entrepreneurs – all aiming to expand the envelope in oil and gas recovery.

Earlier this year, for example, BP announced the establishment of the $100 million International Centre for Advanced Materials (BP-ICAM) to promote the understanding and use of materials for a variety of energy and industrial applications. The 10-year investment program, headquartered at the UK’s University of Manchester, initially will focus on three areas:

• Structural  materials, such as new metal alloys and composites for deepwater production and high-pressure, high-temperature (HPHT) reservoirs;

• Smart coatings for increased protection from the elements and improving a structure’s usable life, protecting pipelines and offshore platforms from corrosion; and

• Membranes and other structures for separation, filtration and purification of oil and gas, water and chemicals in production, refining and biofuels processes and petrochemicals.

The automatic pipe-handling system on the MAERSK DELIVERER reduces the required amount of human interaction with the machinery. The system includes 10 machines that interact in an automated sequence. The semisubmersible is working for Chevron in Angola.

However, the challenge is often not developing the technology itself but changing the mindset, Ms Kverneland of NOV maintains. “The technology is there,” she said. “Today, there are factories producing auto parts that don’t even have the lights on because the work is all being done by robots. The mining industry has had fully automated rigs for years that are remotely operated. We need to adopt these systems, start using them and trust that they will work. Trust is the biggest barrier we have.”

NOV expects its drilling automation system to gain early adopters in 2013 while most companies will take a wait-and-see attitude. NOVA encompasses a new operating control software platform – NOVOS – which includes a planning component that builds the well program into the control system, allowing the rig to automatically follow the well plan, similar to a flight plan. The surface control system will have an application management system, allowing a service company, for example, to write an “app” to the control system and perform intelligent well functions using the system as an interface to the rig.

Ms Kverneland believes the US unconventional shale market will be a testing ground for such automation because of the high volume of wells that need to be drilled efficiently. “If we can improve drilling performance on each well by 30% or 40%, it makes good economic sense.”

Managed pressure drilling (MPD) is another technology that’s expected to make inroads in the coming years, not only in ultra-deepwater fields but also for land applications. Chevron is currently testing a dual-gradient system in the Gulf of Mexico that, if successful, could help to make MPD equipment standard on more offshore rigs. “MPD equipment should be as standard as an iron roughneck or pipe-handling equipment, both offshore and onshore,” Ms Kverneland noted. “We’re not there yet, but we will be in the future.”

Stavanger-based Reelwell is working to commercialize an extended-reach drilling technology that allows the development of reserves from an existing platform, avoiding costly subsea installations while lengthening the life of the field and improving recovery. The company expects to begin a pilot project with several major operators for wells with reaches up to 20 km (65,616 ft).

Among the leaders of drilling innovation is Maersk Drilling, an early promoter of rig automation and “green rig” designs. “We at Maersk see ourselves as a forward-thinking company with an emphasis on the high-end jackup market, especially in Norway,” said Frederik Smidth, chief technology officer. The company is currently building three jackups and four deepwater ships as it works to expand its deepwater operations. “For example, we see automated pipe handling as a given today, not a new technology. Our latest generation of rigs offers a high degree of automation, meaning more machines can be operated in one sequence without human interface.”

The risk/reward balance is an important consideration as the industry pushes the boundaries for bigger, heavier deepwater rigs and 20,000-psi blowout preventer (BOP) stacks. “There are a number technological barriers and risks, but the commercial barriers are bigger for the ultra-deepwater,” Mr Smidth said. “We can overcome the technological risks, but any new technology needs to make economic sense, and operators need to share that risk with the drilling contractors. A new technology must offer improved safety, deliver efficiency for our customers and be cost-effective.”

The Arctic serves as a good case study for that view as the industry considers ways to make year-round drilling feasible in that extreme environment. “For year-round drilling, we need a very robust unit that can be permanently stationed as an offshore hub to launch operations,” he said. The concept is in the early stages of development.

Looking ahead, Mr Smidth sees more integration of surface equipment with downhole tools, with the traditional boundary between drilling contractors and service companies becoming less defined and operations trending to a more open-platform concept. “Drilling contractors need better access to real-time information during the drilling process,” he said. “The current contractual model tends to isolate the contractors from information and prevents us from using new technology.”

He also believes the industry will become more strict in requiring companies to conduct formal testing of software, or software verification, a process Maersk is currently doing to a high degree. “Problems with new equipment are often the result of issues with the software.”

The overriding goal still comes down to relevance and value. “It doesn’t matter how good a particular technology is if it is poorly commercialized,” said Weatherford’s Mark Mitchell. “It won’t be readily available for industry uptake, and it won’t see the benefits of further investment or refinement.”

“In terms of well construction, we like to talk about the concept of investing in drilling reliability and well integrity, meaning consistently delivering planned results with no uncontrolled loss of fluids coming or going with good zonal isolation,” said Brent Emerson, Weatherford’s vice president for well construction products. In that regard, he believes advances in micro-annulus-sealing technology, such as the MicroSeal, which combine older, reliable methods with new technology, has brought significant value to a client’s well integrity.

Right and left, top: TWMA’s RotoTruck, onsite in Dubai, removes cuttings and waste from storage sites and puts them through a thermal treatment process. Left, bottom: TWMA’s TCC RotoMill equipment (in blue), along with a cuttings collection and distribution system, separates hydrocarbon-contaminated drill cuttings into constituent parts of water, oil and solids on a platform rig. The system can process up to 9 tons of cuttings per hour at the rig site, resulting in cuttings that are environmentally safe to be disposed of onsite.

There is also a significant pursuit of tools and equipment to take the industry into deeper waters, with higher pressures and temperatures, Mr Mitchell noted. “Deepwater has proven to be a great incubator for many drilling technologies, such as MPD, top drives, rotary steerables, ERD and 3-D seismic. Today, automation is very much on the critical path, with most efforts aimed at reducing risk associated with surface operations, separating people from hazardous tasks and optimizing the drill floor. We are now starting to see a good deal of focus on closed-loop control systems, such as with automated MPD, to optimize drilling operations, especially in high-risk or highly complex wells.”

R&D investment needs to be a balance – evolving and enhancing technologies to keep production going while developing out-of-the-box technologies that are true game-changers, Mr Emerson added.

“From a service company perspective, the biggest opportunity is in situations where there are a lot of wells and a repeatability factor, as we’re seeing in the unconventional US shale plays. But, if you’re going to be a full-service provider, you have to play in all the arenas. There are not thousands of wells in the Arctic, but the prize is big. Operators see that the reserve potential is enormous in ultra-deepwater and the Arctic, but they have to find a way to drill those areas economically,” Mr Emerson said.

He also believes the industry is investing a tremendous amount of money in new technology, most of it on the right things. “The oil industry is fundamentally very risk-averse, and bringing technology to market takes a long time. And, regardless of how great it is, if it doesn’t work with the processes being used today, it will create a culture gap and become stranded.”

Bringing technologies to market is the mission of Lime Rock Partners, a venture capital firm that funds entrepreneurial firms where many innovations for the oil and gas industry are conceptualized.

“There are two types of technology – one that finds more oil and has a very obvious high-value proposition, and technology that reduces cost,” said Trevor Burgess, managing director at Lime Rock Partners. “Typically, anything related to drilling is about reducing costs, while finding more oil is related to exploration. While there is more excitement in the industry for technologies that increase reserves, those tend to be much harder to develop. Most of the research and development money being spent nowadays is on reducing costs or extending the boundaries of existing technology.”

Independent oil companies are willing to support field testing in the North American land market, which is a strong arena for testing new tools, Mr Burgess noted. But new technologies also are being pushed by what Mr Burgess says are some “enlightened” national oil companies, notably Statoil and Saudi Aramco. “These two companies publish a list of their major challenges and where they believe the best value propositions will be, and challenge the industry to come up with solutions. Then, they help the industry develop the technologies.

“At the same time, the large service companies tend to focus on product evolution, developing technologies designed to improve what they already have,” he continued. An example is the evolution of motors to rotary steerable systems and logging technology. “For these companies, there is lower risk in advancing their own products, or acquiring technologies that can enhance their systems.”

In any case, technology development takes years and significant capital to develop and involves much more than simply commercializing the latest and greatest widget. The ability of a new tool to work in concert with existing systems is critical and an important criterion for Lime Rock.

“We try to find niches where we can introduce technologies that are easily integrated into the oilfield and add immediate value,” said Mr Burgess, who is also chairman of the board of Reelwell, a Norwegian company that is advancing innovative technologies for improving riserless and ERD in wells.

“Anything that has the words ‘revolutionary’ or ‘game-changing’ is a turnoff. Certain work practices have taken years to develop, and new tools need to fit in with the current structure and optimize it.”

In that regard, he is frustrated by criticism that the industry is slow to adopt new technologies. “When one looks at what has been accomplished in the last 20 or 30 years, there have been some outstanding developments,” he said. “Natural gas is cheaper in the US now because of technology. We’re drilling in water depths that 20 years ago were considered unimaginable, and the number of exploratory wells that fail to come to fruition is far less than in it was 30 years ago. The industry has made tremendous strides in lowering the risk of exploration and drilling wells more efficiently and safely. All of this has been made possible with technology.”

Prime examples are horizontal drilling and multi-stage fracturing, which have fueled the industry’s success in tapping North American oil and gas shales. “Any discussion of technology has to address the technology dividend, for example, lower natural gas prices that have led to a reduction in the cost of power, all made possible through these two significant technology breakthroughs,” said Tom Bates, senior advisor for Lime Rock and chairman of the board for Hercules Offshore, Independence Contract Drilling and Global Energy Services.

NOV’s open platform, automated drilling system encompasses a new operating control software platform, NOVOS, that has an application management system allowing “apps” for functions, such as managed pressure drilling. NOV expects its drilling automation system to gain early adopters in 2013, with the US unconventional shale market leading the way as a testing ground because of its high volume of wells.

While it is difficult to quantify the current level of R&D spending in the industry, Mr Bates believes it is where it needs to be for today’s challenges “You must balance risk and reward,” he said. “People won’t invest if they don’t see a return.” Sources of investment have shifted over the last 30 to 40 years, he noted. In the early 1970s, most R&D spending was by international oil companies, while the 1980s and ’90s saw more spending by the major service companies, he noted. “Today, there are substantial dollars being invested from non-traditional sources.” Much of the research into the basic sciences is occurring in the field of nanotechnology, the study of microscopic particles.

“What the industry is waiting for now is the ability to put processing equipment on the seabed and thereby eliminate the need for high-cost platforms,” Mr Bates said. “This has huge cost incentives as the industry pushes into deeper waters.”

The burgeoning deepwater market is indeed proving to be a catalyst for developing high-value innovations, such as the Reelwell Drilling Method (RDM), an extended-reach technology that provides access to fields that are currently too risky or expensive to reach. By extending the drainage from a fixed platform, the system improves recovery and lengthens the life of the field. Reelwell is in the process of commercializing the technology and will embark on a pilot project with several major operators for wells with reaches up to 20 km (65,616 ft), said Reelwell CEO Jostein Aleksandersen.

“With this new method, we can develop reserves from an existing platform and infrastructure, avoiding the need for additional platforms and costly subsea installations,” he said. The system also can facilitate ERD from onshore locations in sensitive regions such as the Arctic, where the thick ice cap presents drilling challenges. “We are talking with a number of operators developing Arctic fields, who need to reach multiple wells from a single land location.”

The drilling method also can be used in reservoirs with hard-to-manage downhole pressures and hole-cleaning issues, commonly seen in horizontal wells, by providing a closed-loop flow circulation system for returning drill cuttings to the surface, Mr Aleksandersen explained.

The company is also developing a riserless drilling method and later this year will embark on a project with a major operator. This riserless drilling method can deliver a significant savings benefit to operators, Mr Aleksandersen said. “Using third- and fourth-generation rigs for deepwater wells implies a 25% to 35% cost reduction,” he noted. “Longer-section slender wells based on 13 ^5/8-in. wellheads implies 20% to 30% reduced time overall to drill a well, and in cases where the two can be combined, the savings could be in excess of 45%.”

Left and right: A Weatherford employee interprets data from the Microflux Control system that combines closed-loop technology with sophisticated, proprietary data acquisition and computer-controlled equipment to enhance rig safety and drilling efficiency. With the goal of removing people from hazardous tasks on the drill floor and reducing risk in surface operations, industry experts are seeing an increasing focus on closed-loop control systems, such as automated MPD, to optimize drilling operations in high-risk or complex wells.

At the other end of the spectrum is a new method of recovering and disposing of drilling waste at the rig site. After developing the technology 12 years ago, Total Waste Management Alliance (TWMA) now provides integrated drilling waste management, engineering and environmental services and technologies for the onshore and offshore oil and industry. The company entered the US land market in 2011 in the Bakken and Eagle Ford plays with its mobile TCC RotoTruck cuttings treatment system.

“We take solids control and cuttings disposal a step beyond traditional shaker and dryer methods to meet increasingly stringent environmental standards and reduce costs for operators,” said Ronnie Garrick, managing director, TWMA. Using the TCC RotoTruck and RotoMill technologies, along with a cuttings collection and distribution system, the company can separate hydrocarbon-contaminated drill cuttings into the constituent parts of water, oil and solids using an alternative process to emulsion. The system can process up to nine tons of cuttings per hour at the rig site. Once cleaned and dried, the cuttings are environmentally safe to be discharged into the sea, disposed of onsite or sent to a non-toxic landfill.

“Corporate responsibility in meeting environmental standards, along with operational challenges of increasingly deviated and deeper wells and more HPHT conditions have been huge drivers in the development of this technology,” Mr Garrick said. “Operators are looking for clean, cost-effective compliance.”

The mobility of the system, through the RotoTrucks, also addresses the logistical and financial challenges of handling waste processing in increasingly remote offshore and land locations, he noted.

IADC president/CEO Stephen Colville addresses attendees at the IADC World Drilling 2012 Conference in Barcelona, Spain, on 13 June.

The drilling world is rapidly changing, and IADC is changing with it. With our strategic review recently completed, we’ve begun reshaping ourselves and have started to roll out new global initiatives aligned with our new way forward. Our agenda is ambitious, but we are totally committed to delivering it on behalf of our members.

IADC provides global leadership for the drilling industry to achieve our core purpose of catalyzing improved performance by enhancing operational integrity and shaping better regulation. Towards this, IADC efforts and activities will be directly focused on members’ critical issues while remaining mindful of stakeholder needs and attitudes. In everything we do, IADC staff will strive to continuously raise IADC’s organizational effectiveness, which will ensure we are delivering maximum value to our members.

On the operational integrity side, IADC has commissioned a detailed study of the existing committee structure to strengthen this critical delivery mechanism for our members. The new structure will ensure more efficient member alignment on issues critical to drilling and completion operations and drive faster delivery of value-adding products.

To foster more active participation with IADC committees and workgroups, regardless of member location around the world, we recently opened the Crown Center of Excellence at IADC’s Houston office. The multipurpose conference and meeting facility can also be used for bespoke training courses to produce the enhanced competence that workers in this industry so urgently need.

Another major step-change launched this year is IADC’s Knowledge, Skills and Abilities (KSA) project, which is developing worldwide competency guidelines for virtually all rig positions, with a priority on safety-critical positions with well control responsibilities.

“The revamped KSAs will provide the industry with a benchmark for globally consistent drilling position requirements, as well as recommend means for effectively evaluating personnel,” said IADC president/CEO Stephen Colville. The first of the competency guidelines will be issued early next year.

A comprehensive update to the IADC Drilling Manual is another critical project we’re taking on. This end-to-end revision aims not only to update existing chapters but also incorporate information on new technologies and industry best practices. The new edition is expected to be published in print and electronic formats, which will allow for continuous updating to keep the manual “evergreen” and abreast of evolving technologies.

To ensure IADC’s services are truly international, the association is looking to expand its global capacity with new offices in key markets and will provide increased support to regional chapters. For example, in Brazil’s large and expanding drilling market, IADC members urgently require representation and assistance on many critical issues.

When it comes to shaping better regulations, IADC is also “stepping up and stepping out.” With both members and regulators increasingly desiring more globalized regulatory regimes, IADC recognizes the need to raise its profile as a proactive champion for drilling companies and drive advocacy on both chronic and critical issues.

For our land members, for example, IADC is actively liaising with the US Bureau of Land Management on its proposed hydraulic fracturing rule that could significantly threaten the land business.

These are just a few of the changes that are brewing at IADC, and many more new and exciting initiatives will be rolled out next year. We invite you to become an active participant in their successful development and delivery.

IADC represents industry in arctic council meeting

Mr Petty represented the drilling industry on the US delegation to meetings of the Arctic Council Task Force for Arctic Marine Oil Pollution Preparedness and Response, held in October and December 2011 in Oslo, Norway, and St. Petersburg, Russia, respectively.

The task force was commissioned to promote awareness of and cooperation in sharing information, response equipment and personnel across the Arctic in response to a major spill event. IADC’s attendance as a private-sector participant was requested by the US Coast Guard to provide industry perspectives on suitability of equipment, equipment stockpiles and logistical considerations in identifying, mobilizing, deploying and demobilizing equipment.

In her invitation to IADC, Coast Guard Rear Admiral Cari Thomas, who headed the US delegation, noted that IADC’s insights and knowledge specific to the drilling industry would enhance discussions at the meeting.

Shell, representing IPIECA, was the only other industry participant invited.

Besides the Coast Guard, the other federal agencies represented in the delegation were the US Bureau of Safety and Environmental Enforcement (BSEE) and the National Oceanic and Atmospheric Administration. Government representatives from all Nordic countries, as well as Canada, the United States and Russia, also made presentations.

The task force is co-chaired by ambassadors Karsten Klepsvik of Norway, Anton Vasiliev of Russia and David Balton of the US.

A first draft of an agreement among the eight Arctic states, prepared by Norway, was reviewed at the December meeting. It was the consensus that the instrument will be binding. The group also agreed that only oil spills will be included. All sources of spills are included: shipping, oil and gas E&P, cargo ships, terminals, tourism ships, pipelines, etc. Military ships and installation oil spills are excluded.

Each article within the instrument was reviewed, and states were given opportunities to discuss what should be included or excluded. The goal is to deliver the final instrument for signature at the May 2013 meeting of the Arctic Council Ministers.

UK’s highest court upholds WTD ruling

The culmination of eight years of litigation in UK courts, the UK Supreme Court upheld the previous rulings of the Court of Session and Employment Appeal Tribunal that time off work enjoyed by UK offshore oil and gas workers more than meets the minimum legal amount of annual leave that employers must provide their employees.

Typical rotas worked offshore allow for more than 26 weeks onshore, away from work, more than meeting the requirement of the Working Time Directive (WTD) to provide 5.6 weeks of annual leave.

This Supreme Court decision is final and can’t be appealed to the European Court of Justice.

Industry comments on draft PEIS for OCS program

Providing comments to be considered before the Draft Programmatic Environmental Impact Statement (DPEIS) is finalized for the proposed 2012-2017 Outer Continental Shelf (OCS) leasing program, seven industry groups, including IADC, reiterated disappointment in the limited scope of the DPEIS. However, the groups also expressed support for the work of the US Bureau of Ocean Energy Management (BOEM) in preparing for the DPEIS.

Comments were submitted in early 2012 to James Bennett, BOEM Division of Environmental Assessment chief. They pointed to the missed opportunity to increase access to additional OCS energy resources in the Eastern Gulf of Mexico, offshore Alaska and on the US East Coast, especially offshore Virginia. “The result is greater dependence on foreign sources of oil and gas,” the groups stated.

However, with as many as 15 lease sales among the six OCS planning areas in the proposed action plan, industry believes the DPEIS includes an acceptable range of offshore access.

The groups further identified numerous areas where further attention to the statements made is needed, as well as areas where there is incomplete or unavailable information.

Regulators were urged to use existing legal authorities and mechanisms as the foundation for future actions to carry out coastal and marine spatial planning. In addition, the coexistence of native subsistence hunting and fishing and modern commercial development in Alaska demands more thought in the context of future lease sales.

86 groups object to trade agency reorganization

Eighty-six groups representing the business and agricultural communities, including IADC, jointly wrote to US President Barack Obama expressing concerns over a proposal to merge the Office of the US Trade Representative (USTR) with five other agencies into a single cabinet-level department.

The USTR plays an invaluable role in coordinating the different entities within the US government with specialized trade functions based on expertise. By balancing the interests of various constituencies and agencies, the USTR provides assurance “that no one has a thumb on the scale,” the letter stated.

As a separate entity within the Office of the President, the USTR is able to act responsively to negotiate, implement and enforce US trade objectives. The USTR is actively involved in growing US exports, eliminating foreign market barriers and improving the overall competitiveness of US farm and manufactured goods and services in the global economy.

Mr Petty, in his capacity as ITAC2 chairman, counsels the US Trade Representative and the US Secretary of Commerce on international trade issues. Mr Petty also was designated by the US Secretary of Commerce and USTR as chairman of the Investment Working Group of the Department of Commerce Industry Trade Advisory Committees (ITACs).

OGP responds to proposal for EU offshore safety initiative

Responding to the proposal for an EU safety initiative for the offshore oil and gas industry, the International Association of Oil & Gas Producers (OGP) has asked the European Commission to look to legislation in the form of a directive that would allow member states to adjust to local circumstances and align with existing regulatory frameworks.

IADC has been actively involved with development of OGP’s position paper, which was delivered to the commission’s Directorate-General for Energy in January.

The paper notes that the offshore E&P industry has developed recommendations for improving well incident prevention, intervention and response capability over the past couple of years. This work has already achieved better engineering design and well operations management, improved capping devices, and enhanced oil spill preparedness and capability.

The paper also details OGP’s concerns with several key issues.

• Europe’s offshore oil and gas activities would come to a halt unless there are adequate transition periods to ensure consistency between national legislation and the proposed regulation. A transition time line should follow a risk-based approach to allow prioritizing higher-risk activities, and revision of environmental and safety documentation should not follow a one-size-fits-all approach.

• Numerous definitions require clarifications before industry could operate under the proposed regulation, and these definitions must be consistent with the body of definitions currently used in member states. Changes to definitions, including “operators” and “major accident,” are proposed.

• A mandatory separation of licensing procedures would be against common and proven practice and would jeopardize industry’s contribution to employment and economic growth in Europe. Important economic incentive structures in place could be damaged. Further, OGP does not recognize that the proposed changes would add to an existing safety regime.

• Amending the Environmental Liability would unnecessarily increase the legal uncertainty while the commission is conducting a review of risk and liability.

• Mandating independent verification by a third party would not necessarily lead to an increase in safety standards. Second-party verification is acceptable and effective in many circumstances.

• The industry is in favor of continuous improvement and believes the ordinary legislative procedure, which allows for engagement of all stakeholders, is more effective than delegated powers.

• MODU 2009 is effective for rigs constructed after 1 January 2012. However, existing rigs would not be in compliance and would be excluded from use in the EU. The proposal should allow for the use of rigs in accordance with earlier revision versions of the code, as long as all remaining requirements of this regulation are met.

Amicus brief supports Beaufort exploration plan

Industry groups jointly filed an amicus brief in defense of the US government’s approval of Shell’s Beaufort Sea exploration plan. IADC was joined by the API, US Chamber of Commerce, National Association of Manufacturers and the US Oil and Gas Association in filing the document with the US Ninth Circuit Court of Appeals in February.

The court previously rejected efforts to block Shell’s planned exploratory activities in the Beaufort and Chukchi seas in 2010, yet petitioners continue to seek to frustrate fundamental congressional objectives regarding the timing and character of the approval process for activities on the Outer Continental Shelf (OCS).

The amicus brief emphasized that the Interior Department’s approval of Shell’s 2012 revised exploration plan, following the preparation of an extensive environmental assessment, plainly complies with the requirements of reasoned decision making. This conclusion is supported by Congress’ adoption in the OCS Lands Act of a goal to encourage “expeditious” OCS exploration and production. Congress dictated that exploration plan approval decisions must be made within 30 days of plan submission and should be based on existing information. Approval should be forthcoming unless exploration would cause serious harm.

Further, thousands of OCS exploration plans have been approved under that time table and standard.

“Petitioners have failed to show an entitlement to have the approval decision set aside or vacated,” the brief stated.

Industry urges suspension of National Ocean Policy

IADC, NOIA and IPAA urged the National Ocean Council (NOC) to suspend implementation of the National Ocean Policy (NOP), pointing to major weaknesses in the draft implementation plan and a myriad of unanswered questions.

In a letter sent to NOC, industry groups said their chief concern lies with the anticipated use of coastal and marine spatial planning (CMSP), which could pose additional obstacles to access for oil and natural gas resources on the Outer Continental Shelf (OCS). Its use could mean that the requirements of “expeditious development” directed by the OCS Lands Act will be limited, leading to potentially serious conflicts. The NOC has not provided any more detail or recognition of how the NOP will avoid such conflict, the letter said.

Further, the CMSP may result in decisions being made about setting significant areas of the OCS off limits to future access without the benefit of knowing what resources lie underneath those areas. “It would be very shortsighted to make CMSP decisions without the benefit of new data,” the groups stated. At a minimum, new geological and geophysical data should be obtained.

The groups also pointed out that a national ocean policy is incomplete without greater recognition for how increased access to the OCS might help realize national policy objectives of job creation, greater energy security and reliability, and greater federal revenues derived from increased oil and gas activities. As such, suspension of policy implementation is needed until studies analyzing the potential economic, societal and legal impacts have been carried out and full engagement with Congress has taken place.

If the administration decides to move forward with implementation, a pilot project in one region should be undertaken. This would ensure a greater likelihood of meaningful stakeholder involvement and fewer unintended consequences.

Governors coalition pushes for more E&P access

The Outer Continental Shelf (OCS) Governors Coalition urged the Obama Administration to expand access to new offshore areas for energy development and to update evaluations of OCS resources. In a letter to President Obama from the governors of Alabama, Alaska, Louisiana, Mississippi, South Carolina, Texas and Virginia, the coalition noted that expanded access and new reserve assessments were among its top priorities for 2012.

“We remain disappointed by the administration’s failure to include new leasing areas in the Proposed Draft Five-Year Plan for Oil and Gas Leasing for 2012-2017,” the letter stated.

Despite strong bipartisan support from Virginia, the administration did not reinstate a lease sale offshore Virginia. “We urge the administration to consider more thoroughly the wishes of the affected states when considering offshore leasing plans,” the governors said.

Concerns also were expressed with the National Ocean Council and the proposed coastal marine spatial planning, noting that better understanding is needed of the bureaucratic hurdles that will be erected through the process.

Policymakers also need updated evaluations of OCS resources, included assessments in areas not currently available for leasing, they said. Such information would allow the federal government and states to set more informed policies.

Also among the coalition’s priorities is accelerating the pace and level of permitting for offshore E&P. “While some progress has been made to decrease the average wait time for approvals, we would urge stronger, swifter action,” the letter said.

Business groups urge facilitation of US investments in Burma

IADC was among 13 organizations that submitted a letter to President Obama urging the Administration to open the door to Burma’s further involvement in the US business community. With the victory in Burma’s by-elections signaling an improved electoral process, US companies have the opportunity to create the jobs and economic base needed for Burma to jump-start its economy and meet the expectations of its people, the letter stated.

“US companies can and do provide capacity building, training and respect for the environment, as well as projects to engage with communities where they work to a substantially greater degree than most of our competitors from other nations. As we have so often seen, the presence of US businesses and foreign investment inevitably helps lead to an improved human rights environment,” according to the groups’ letter.

The Administration was urged to lay out a plan that eases restrictions on private investment across all sectors and includes the same rules for all businesses. “Most urgently, the lifting of financial services facilitation and transactions sanctions will be essential to the sustainable expansion of the Burmese economy and the successful operation of any US business effort,” the letter stated.

Irish agency urged to reconsider regulations

IADC is among several industry organizations that the Irish Offshore Operators’ Association (IOOA) has recommended to meet with Ireland’s National Parks and Wildlife Service (NPWS) with the purpose of discussing proposals to protect marine mammals from man-made sound sources. The IOOA believes that the proposed changes are likely to result in drilling operations and seismic surveys taking substantially longer while offering little, if any, additional protection to marine life.

In comments submitted to the NPWS, the IOOA noted that extension of the 2007 Guidance to include drilling operations requires more consideration. Typical drilling operations are not continuous and don’t generate a constant sound pressure level. Drilling operations are complex and require a range of different activities, and this must be recognized in the Draft Guidance, IOOA stated.

Further, they noted that drilling in frontier regions is extremely cost sensitive. Application of the Draft Guidance could substantially increase the length of time a drilling rig will be on location, potentially resulting in the operation becoming prohibitively costly.

It was also noted that the oil and gas industry is accustomed to undertaking environmental impact assessments and identifying risk mitigation measures. A clear understanding by all parties is needed on what constitutes an adequate demonstration that the relevant risks have been identified. The NPWS was asked to clarify its expectations.

In a section detailing operational considerations concerning marine mammal observers, the introduction of a general sea condition where reliable observations are viewed as possible could be problematic in areas characterized by long periods of relatively high sea states.

IOOA concluded by suggesting that, before the Draft Guidance is finalized, a meeting with IADC, IOOA, OGP and the International Association of Geophysical Contractors be held. Interpretation and application of the Draft Guidance should be discussed, and alternative approaches to protect marine mammals should be explored.

Lawsuit challenging GOM leases dismissed

A judge dismissed claims by the Defenders of Wildlife challenging Gulf of Mexico oil and gas activities in Macondo’s aftermath.

Chief US District Judge William Steele granted the summary judgment motions of the Federal Defendants (Bureau of Ocean Energy Management/BOEM) and Industry Intervenors (including IADC, API, IPAA and the US Oil & Gas Association).

The plaintiff argued that 331 leases issued by the BOEM pursuant to Lease Sale 213 violated the Endangered Species Act and the National Environmental Policy Act.

With Judge Steele having previously granted the Federal Defendants’ and Industry Intervenors’ motions to dismiss plaintiff’s other claims, the lawsuit has now ended in a complete victory for the industry.

IADC calls for US accession to Law of the Sea Convention

IADC was among 12 organizations that wrote to the US Senate Foreign Relations Committee in June urging US accession to the UN Convention on the Law of the Sea. Accession would provide American businesses certainty and legal equality to the largest of the Exclusive Economic Zones (EEZ) under the convention, as well as the corresponding natural resources and shipping rights of way. Further, accession would provide much-needed certainty and predictability to claims of control over territory in the Arctic, the organizations noted in the letter sent to Sen. John Kerry, committee chairman, and Sen. Richard Lugar, committee ranking member.

“Now that new technologies and changed conditions have made it cheaper and easier to access the potential wealth beneath the oceans, the business community simply cannot afford to have the US remain on the sidelines,” the letter stated. Energy companies need the certainty the convention provides to explore beyond 200 miles and place experts on international bodies that will delineate claims in the Arctic. The convention secures each coastal nation’s sovereign rights over living and non-living resources and the marine environment of the 200-mile EEZ.

The convention also provides favorable conditions for securing access to the continental shelf beyond 200 nautical miles. Proper delineation of the extended continental shelf could bring an additional 4.1 million sq miles of ocean under US sovereign rights.

“Accession to the Law of the Sea Convention is the only means to protect and advance the claims of US entities to the vast mineral resources contained on the deep seabed floor and would ensure that ships flying American flags travel safely and securely through international waters,” the groups urged. To date, 161 countries and the European community have signed and ratified the convention.

IADC applauds effort to improve OCS leases

IADC and its allies API, NOIA and IPAA have expressed strong support for HR 6082 in a joint letter to US Rep. Doc Hastings, R-Wash., noting that the bill proposes significant improvements to the Obama Administration’s final OCS Oil and Gas Leasing Program for 2012-2017. Congressman Hastings is chairman of the House Committee on Natural Resources, which has jurisdiction over OCS leasing and which reported HR 6082 to the full House. HR 6082 is titled “Congressional Replacement of President Obama’s Energy Restricting and Job Limiting Offshore Drilling Plan.”

“The provisions in HR 6082 propose a more robust offshore leasing program that would encourage a greater number of offshore projects, resulting in greater growth in domestic oil and natural gas production and create jobs in far greater numbers than could be expected from the Administration’s final program,” IADC, API, NOIA and IPAA wrote in a letter initiated by IADC and drafted by all four associations.

HR 6082, if enacted into law, also would begin the process of determining how to lease and develop federal resources offshore Virginia.

“It is through drilling exploration activities in the new areas provided by HR 6082 that will lead the country to greater energy security,” the letter stated.

IADC supports Trans-Pacific Partnership for investment in services

IADC was among 22 organizations that wrote to US Trade Rep. Ron Kirk in June in strong support for a Trans-Pacific Partnership (TPP) agreement that would aim to liberalize cross-border trade and investment in services.

The benefits of raising the level of trade and investment in services across the Pacific has the potential to ripple through the manufacturing and agricultural sectors as well, given the “TPP includes disciplines and market-access commitments that support the services sector, building upon high standards achieved through existing bilateral and plurilateral free trade agreements (FTAs) between the US and its trading partners,” the letter stated. The services sector accounts for 70% of world economic output and 70% of employment.

The organizations suggest the TPP should address:

• High standards achieved in services, financial services, investment and intellectual property in recent FTAs;

• New and increasing challenges in the international economy, which have the potential to distort trade and investment and undermine the competitive opportunities for US enterprises;

• Express delivery services to strengthen and improve previous FTAs, maintaining standards and not diluting them;

• Cross-border information flows that do not mandate the use of local computing infrastructure and that digital products are not subject to customs duties and fees; and

• Rules to prohibit regulations requiring local content for service providers, as well as prohibit requirement that business services be provided locally.

TPP members, including Canada and Mexico, accounted for more than $823 billion in worldwide services exports in 2010. In the US alone, about 80% of the Gross Domestic Product and 80% of employment are in services, where US services exports in 2011 totaled $589 billion – more than the combined sums of the second-ranked Germany and third-ranked Britain.

“The price and quality of services also influence costs and productivity in other sectors of each economy,” the groups stated. “Thus, when liberalized and made more efficient, services have a strong multiplier effect on the competitiveness of every economy.”

Industry wins dismissal of lease sale lawsuits

Two separate lawsuits challenging a Gulf of Mexico (GOM) lease sale were dismissed. In 2010, the Defenders of Wildlife and other NGOs in Alabama federal district court challenged the issuance of leases pursuant to Central GOM Lease Sale 213; the Center for Biological Diversity (CBD) in DC federal district court also filed a challenge.

Although Lease Sale 213 was conducted before Macondo, many leases were not issued until after the event, and the lawsuits challenged that the then-Minerals Management Service issued leases without engaging in new National Environmental Policy Act (NEPA) and Endangered Species Act (ESA) analyses.

Industry associations succeeded in persuading the Alabama court first to dismiss all claims other than those relating to Lease Sale 213, and then to dismiss the Lease Sale 213 claims themselves. Defenders of Wildlife initially appealed the latter ruling to the Eleventh Circuit but later dropped the appeal.

Similarly, the DC court dismissed all claims other than those relating to Lease Sale 213, and the Lease Sale 213 claims remained pending, which made industry potentially vulnerable to an adverse ruling in DC on the Lease Sale 213 claims.

However, the CBD and the government have agreed on a Stipulation of Dismissal. The CBD dismissed its Lease Sale 213 NEPA claims with prejudice, and the CBD dismissed its Lease Sale 213 ESA claims without prejudice. The CBD will be able to pursue the ESA claims in the future only if the BOEM fails to complete its ongoing renewed ESA consultations by May 2013.

Separately, IADC, API, the Independent Petroleum Association of America and the US Oil & Gas Association are working to fight challenges to Lease Sale 216/222. Industry groups have filed a motion to intervene in the litigation challenging the 20 June 2012 sale, which resulted in more than US $1.7 billion in high bids on 454 tracts.

Oceana, Defenders of Wildlife and the CBD challenge the adequacy of the Supplemental Environmental Impact Statement prepared by BOEM with respect to Lease Sale 216/222 pursuant to NEPA.

Industry groups believe they are entitled to intervene in this litigation as of right or through permissive intervention. The court recently granted the group’ motion to intervene in a similar lawsuit challenging Western GOM Lease Sale 218.

IADC criticizes BSEE noncompliance citation policy

IADC has expressed concern about the Interim Policy Document by the US Bureau of Safety and Environmental Enforcement (BSEE), which affirms that BSEE inspectors can issue Incidents of Noncompliance (INCs) to drilling contractors as well as oil companies. The unprecedented policy demonstrates a significant deviation from the global paradigm of holding operators ultimately responsible for accidents at the well site.

“BSEE’s guidance is inconsistent with the industry model and creates a whole new area of ambiguity,” Mr Petty said. Global government regimes have always held operators responsible, he said.

“This new guidance opens the door to unknown levels of liability for contractors and additional uncertainty for contractors. At a minimum, it could increase contractors’ insurance premiums, but it also could potentially eliminate coverage for many companies in the US altogether.” Such additional costs and uncertainty could drive contractors out of the US Gulf of Mexico.

In late 2011, Mr Petty already spoke to Dow Jones newswire on behalf of the drilling industry to assert that BSEE fining contractors who worked for BP on the Macondo well lacks precedent and could deeply trouble the insurance market for offshore drillers.

By pursuing contractors, regulators “give a green light for others to go after them – on the same basis and on the same level as primary operators,” Mr Petty said. The comment was given just before BSEE notified Transocean and Halliburton of the initiation of civil penalty proceedings against their companies in late 2011. The Outer Continental Shelf Lands Act allows the government to collect $40,000/day per violation.

Sen. David Vitter, R-La., questioned the legal basis for fines as well. “There needs to be a full accounting of the legal analysis behind (the Department of) Interior’s expansion of authority,” Sen. Vitter said.

Sen. Vitter sends Letter of concern to bsee over expansion of authority to include contractors

Sen. Vitter sent a letter to BSEE director James Watson in October 2012 indicating his concern with BSEE’s interim policy document on “Issuance of an Incident of Noncompliance (INC) to Contractors (IDP No. 12-07).”

Sen. Vitter stated that he is concerned with the expansion of BSEE’s current regulatory authority to include contractors. He also requested “adequate information justifying this policy, including the agency’s internal legal analysis,” as a means of transparency.

“The guidelines put forward by BSEE in IDP No. 12-07 are still non-specific to their intent and open ended in their application,” Sen. Vitter wrote. “As a result, the offshore service industry is in a quandary as to what liability for contractors will be in the future and what their vulnerability will be to agency actions.”

The senator also said that the offshore industry feels this policy “is a major, unprecedented departure from past practices on the US Outer Continental Shelf.”

As a suggestion, Sen. Vitter wrote that BSEE should initiate a formal rulemaking process that would promote transparency and allow all stakeholders the chance to provide their input before the agency enforces such a policy.

Rig owner not responsible party in Macondo, judge rules

Under the Oil Pollution Act (OPA) of 1990, Transocean is not a “responsible party” for discharge beneath the water surface in the Macondo spill, US District Judge Carl Barbier ruled in February. Because the Deepwater Horizon was being used as an offshore facility at the time of the incident, BP and Anadarko, as co-lessees of the area in which the offshore facility was located, are responsible parties with regard to subsurface discharge, the ruling said.

Under the Clean Water Act (CWA), the judge noted that “it is logical that the responsible parties for a discharge under OPA would also be liable for penalties under the CWA.” Further, he found that the subsurface discharge was not from the rig but from the Macondo well.

The judge did not address liability regarding any surface discharge that may have occurred, and it was noted that a question remains as to whether Transocean would be considered an “operator” of the offshore facility, as the CWA definition of “operator” provides little guidance. Whether Transocean meets this definition is “disputed.”

Industry comments on fracturing guidance

IADC, along with the Independent Petroleum Association of America, the Association of Energy Service Companies and the International Association of Geophysical Contractors, recently submitted comments to the US EPA in regards to permitting guidance for oil and gas hydraulic fracturing activities using diesel fuels.

The groups urged the EPA to retract both its website assertion of an Underground Injection Control (UIC) permitting requirement under the Safe Drinking Water Act (SDWA) and the Draft Guidance document.

The industry groups believe the EPA should “revisit its use of this authority in the context of (1) the current state regulatory programs and (2) the mandates of the SDWA prohibiting regulations that would impede or interfere with American oil and natural gas production unless requirements are essential to assure that underground sources of drinking water (USDW) will not be endangered by injection.”

The EPA and other federal officials have repeatedly confirmed that hydraulic fracturing has not adversely affected USDW. Industry groups believe the EPA’s actions have violated its overarching SDWA mandate.

The EPA’s Draft Guidance also seeks to expand the group’s authority, which is limited to regulating the use of diesel fuel in the context of hydraulic fracturing. The EPA has proposed regulation of chemical products that are not diesel fuel, and current and proposed actions threaten the federal-state primacy structure. Further, the definition of diesel fuel must be written to be easily understood, certain and stable.

Industry suggests the EPA initiate a rulemaking process that includes examination of:

• Whether authority of the SDWA needs to be used or if existing state regulatory programs effectively manage the risks of diesel fuel use in hydraulic fracturing;

• If the authority is used, what is the appropriate structure under the UIC program;

• To what extent is diesel fuel used in the fracturing process and to what extent will it continue to be used if a new federal requirement is created; and

• How the creation of new requirements will affect American oil and natural gas production within the mandates of the SDWA.

Industry to BLM: Well stimulation rule not needed

IADC, IPAA and more than 40 other groups have jointly filed comments urging the US Bureau of Land Management (BLM) to withdraw its proposed rule on well stimulation, including hydraulic fracturing, that was published in the Federal Register on 11 May 2012. Noting that there have been no incidents of contamination from hydraulic fracturing in over 1.2 million wells in more than 60 years, the groups called the proposed rule unwarranted.

“We are concerned that the rule is a misguided attempt to address concerns with well stimulation that may be based on inaccurate or unsubstantiated claims relating to the environmental and health impacts of the processes,” the 30-page comment document stated.

Industry groups further noted that the BLM’s proposed rule ignores the scope and effectiveness of existing state regulations, as well as issues related to state/federal water rights.

From an economic point of view, the proposed rule also will have a severe negative impact on small businesses, many of whom will not be able to endure the added compliance costs. It’s estimated that the total aggregate cost for new permits and well workovers alone resulting from this new rule would range from US $1.499 billion to $1.615 billion annually in just 13 western states. This is a conservative estimate of the delays and costs associated with the rule, equating to about $253,800 per well and $233,100 per re-fracture stimulation, the groups stated.

IADC to revamp Drilling Manual

IADC has launched an initiative for a comprehensive revision and update of the IADC Drilling Manual. The end-to-end revision aims not only to update existing chapters but also incorporate information on new technologies and industry best practices. As envisioned, the 12th edition will be published in print as well as electronically, featuring graphics, videos and animations.

“The update of this important industry resource will provide the industry with better materials that will catalyze improved performance at the rig site and the operations office,” Mr Killalea said. “In addition, we intend to maintain the IADC Drilling Manual as an evergreen resource, with regular updates by an informed group of technical experts.”

Fran Kennedy-Ellis, who recently joined IADC as director – publishing initiatives, is organizing a steering committee to shape the work ahead.

Subject-matter experts are needed to contribute on all aspects of drilling operations. Further, young professionals are encouraged to participate.

A kick-off meeting will be held on 28 November at IADC’s Houston office.

FTS holds Subsea BOP Workshop

IADC held a Subsea BOP Workshop on 30 October in Stavanger, Norway. The event, organized under the auspices of the IADC Future Technology Subcommittee (FTS), seeks to identify BOP-related problem areas for operators, drilling contractors and OEMs and foster discussion among BOP technology developers and users.

FTS vice chairman Dustin Torkay, Seadrill Americas, provided welcoming remarks. Presentations then followed from Helge Ørgersen, Statoil; Per Wullf, Seadrill Management; David Dietz, GE Oil & Gas; and Mel Whitby, Cameron Drilling Systems. Technology sessions for the afternoon covered explosive shearing, electric BOP controls and BOP monitoring, followed by a panel discussion.

ART workshop addresses drilling automation

The IADC Advanced Rig Technology (ART) Committee held a workshop on 12 June in Barcelona, Spain, in advance of the IADC World Drilling 2012 Conference & Exhibition, looking at drilling automation advances.

The half-day event included presentations from Mr Torkay on whether well construction is behind the innovation curve; from Shell’s Jan Brakel on the level of innovation within the well construction industry; and from Bibek Das of ABS on managing the risk of new technology.

A panel session followed looking at how industry could collaborate to accelerate drilling innovation economically and sustainably. Participants were Hege Kverneland, National Oilwell Varco; Gregers Kudsk, Maersk Drilling; Mike Power, Chevron; Joop Roodenburg, Huisman Equipment BV; and Tom Bates, Lime Rock Partners. The panel was moderated by John de Wardt, De Wardt & Co.

Shale workshop results presented at drilling conference

The Future Technology Subcommittee of the IADC Advanced Rig Technology Committee presented results from a 2011 shale workshop in a paper, IADC/SPE 150971, at the 2012 IADC/SPE Drilling Conference in San Diego, Calif., on 8 March. More than 100 technology leaders and engineers attended the shale drilling technology and challenges workshop on 25 January 2011, the second in a series of planned events to address technology needs that were identified in a 2009 industry survey.

Operator and contractor perspectives on urban shale drilling that were presented at the workshop were shared with Drilling Conference attendees, along with results of sociology studies of the onshore oil and gas industry and the perceived challenges of drilling in urban environments.

The Operational Integrity group – consisting of the Offshore Division, Onshore Division, Drilling & Well Services Division, and Accreditation & Certification Department – have been busy throughout the year promoting the interests of IADC members through various regulatory activities and major initiatives like our KSA project.

In addition, this year marked the opening of our new Crown Center, a multipurpose, versatile meeting facility that was designed to provide a home within IADC’s Houston office for the association’s committees, task forces and other workgroups engaged in activities important to our members. We’re also in the midst of a comprehensive review of all of our committees and their structure to ensure they are focused on critical issues and aligned with our members’ needs.

A side of IADC not often seen by our members is the bulk of our behind-the-scenes work with other industry groups and collective regulatory bodies.

Throughout the year, IADC has been actively engaged with the Wells Expert Committee of the International Association of Oil & Gas Producers (OGP). Within the WEC, we are active on both the Human Factors, Training & Competency Task Force and the BOP Technology Task Force.

The former will soon release its first document, a report on recommendations on technical enhancements to well control training, examination and certification.  Even before its publication, a number of the recommendations in this report were already being considered as enhancements to our well control efforts by the WellCAP Advisory Panel.

In the BOP Task Force, IADC has been working with OGP to respond to a request posed by the International Regulators Forum to evaluate the reliability and functionality of subsea systems. That effort has culminated in a study now under way, as both groups reported to a meeting of the IRF in September in Brazil. As also reported to the IRF, IADC is taking a step toward rig crew competency with our KSA project, in addition to ongoing maintenance of our HSE Case Guidelines and a proposed new bridging document, which will function as a companion to the guidelines.

In the year ahead, we’ll be adding more capability to the group. We recently hired Scott Maddox as director of drilling and well services, who will be responsible for overseeing the Underbalanced Operations & Managed Pressure Drilling Committee, Advanced Rig Technology Committee and Well Servicing Committee.

We are also in the process of bolstering the Onshore Division with the addition of land rig operations specialist, and we’ll be taking our popular Land Operations Forums “on the road” in an effort to involve more members on a regional and local basis.

Alan Spackman, vice president – offshore technical and regulatory affairs

IADC MODU HSE Case

At its September 2011 meeting, the IADC HSE Case Users Group adopted amendments to the MODU HSE Case Guidelines to address gaps identified through a gap analysis against the provisions of API RP 75 and the SEMS rule of the US Bureau of Safety and Environmental Enforcement (BSEE). The changes addressed temporary refuge and escape routes, drawings and schematics, design and commissioning of new facilities, management of change, job safety analyses and record retention.

The September 2012 meeting of the Users Group concluded that no additional amendments to the guidelines would be made at this time but noted that results of various regulatory initiatives that are being considered will need to be reflected in the guidelines’ legislative annexes, if not in the guidelines themselves. These initiatives include those of the European Commission, Australia, New Zealand and the US. The 2012 meeting was also asked to give preliminary consideration to the development of globally applicable guidelines on bridging arrangements, modeled on the proposed API/IADC Bulletin 97, Well Construction Interface Document.

Industry suggests revisions for BSEE’s SEMS 2 regulations

IADC and other industry groups provided detailed comments to BSEE in response to their proposal for a revision of their recently issued safety management systems regulations (SEMS 2). Among the suggestions offered by the joint industry group were :

• Wording related to BSEE jurisdiction “creates considerable and unacceptable ambiguity,” exacerbated by the inclusion of well intervention activities in the proposed definition of MODUs.

• To avoid confusion, the definition of MODUs should be consistent with the published definition in the MOU and API RP75.

• The proposed rule contains conflicting statements as to whether the operator or contractor is responsible for training contractor employees.

• The availability of independent third-party auditors (I3Ps) was not assessed in relation to the proposed requirement for the use of I3Ps. The criteria to allow an established internal work force to continue to conduct audits should be reconsidered and defined, and a realistic timeline for implementing such a requirement is needed.

• The effective date for requiring employee participation was not specified.

• Revisions to the wording of the requirement for reporting of unsafe work conditions were suggested corresponding to a similar existing requirement.

Industry also noted that many in the industry have already voluntarily embraced API RP75 and implemented and evolved their SEMS prior to SEMS rulemaking. It’s also unclear how the agency will assess the effectiveness of an operator’s SEMS and delineate the purpose of SEMS audits of critical processes from typical agency compliance inspections.

In separate comments, IADC identified shortcomings in the proposed regulations, particularly with regard to the ambiguity in their application to combined operations and in how they proposed to place “ultimate work authority.”

Safety management systems for arctic operations

Supporting IADC’s Government Affairs efforts, Mr Spackman represented IADC in a June workshop in Keflavik, Iceland, on Protection of the Arctic Marine Environment that  focused on safety management systems and their role in the prevention of marine pollution, with particular reference to arctic operations. This was followed by a September workshop in Halifax, Nova Scotia, where a group of invited experts from various industries, regulators, government bodies and academia on safety culture, oil and gas operations, and Macondo investigations and their findings and recommendations were asked to examine the role that safety culture played in the accident. IADC was represented by Julia Swindle, industry compliance specialist, at that workshop.

Caribbean-region spill issues examined

In December 2011, the IMO/UNEP Regional Activity Center for the Wider Caribbean held a seminar in Nassau, the Bahamas, to discuss regional needs related to potential spills associated with offshore oil and gas development in the wider Caribbean region and to lay the groundwork for future regional assistance and cooperation. The seminar included discussions of national oil and gas development projects and national capabilities, regulatory programs to prevent and respond to uncontrolled flow from a well, and national and regional capabilities to do so.

Countries sending delegates to the seminar were the Bahamas, Cuba, Jamaica, Mexico and the US. Mr Spackman participated as a member of the US delegation, along with representatives of the US Department of State, EPA, NOAA, Coast Guard and BSEE.

Follow-up workshops have been held in Curacao, Jamaica and Mexico to facilitate information sharing and strengthen regional cooperation on oil spill prevention and response planning focusing on offshore oil and gas exploration and production activities.

IMO Maritime Safety Committee actions to affect contractors

Mr Spackman recently represented the association at the 90th session the IMO Maritime Safety Committee (MSC), where several actions were approved that will affect offshore drilling contractors.

• Accepting a proposal by the Bahamas, the MSC has directed its Sub-Committee on Dangerous Goods, Solid Cargoes and Containers to develop amendments to the IMO MODU Codes to ensure that the provisions of the recently approved SOLAS regulations requiring periodic confined space rescue drills are extended to MODUs. Regulatory text to be considered at the Committee’s December 2012 session will amend all three editions of the MODU Code to require such drills to be performed every two months.

• Accepting a proposal by Liberia, the Marshall Islands, Vanuatu, IADC and the International Marine Contractors Association (IMCA), the MSC has directed the Sub-Committee on Standards of Training and Watchkeeping (STW) to revise Resolution A.891(21) on recommendations on training of personnel on mobile offshore units. IADC is preparing a comprehensive proposal that will be submitted to STW for consideration at its April 2013 session.

• Accepting a proposal by the US, IADC and IMCA, the MSC also directed the Sub-Committee on Ship Design and Equipment to develop amendments to MSC/Circ.645 on guidelines for vessels with dynamic positioning systems.

• In approving new SOLAS regulations aimed at prohibiting chemical processing onboard ships at sea, the committee also accepted amendments to the proposed regulation that were proposed by Liberia, the US, Vanuatu, IADC, IMCA and the Oil Companies International Marine Forum that exempted offshore oil industry vessels from the SOLAS amendments. Had the exemption not been included, the SOLAS regulations could have been interpreted to prohibit onboard mixing of downhole fluids and cements.

Other IMO activities of concern

Tier III engine emission standards. Regulation 13.10 of MARPOL Annex VI calls for a review of the status of technological developments to implement the Tier III NOx emissions standards to be completed at the May 2013 session of the Marine Environment Protection Committee in order to determine their availability for implementation in 2016. Two technologies have been put forward as being available to allow the IMO to implement the standards: selective catalytic reduction (SCR) and exhaust gas recirculation (EGR) technologies. IADC remains concerned that, while these technologies may be available, they may not be appropriate for the particular operational conditions of MODUs, particularly the engine load profiles for drilling operations and the operating areas where the availability of redactant for SCRs may not be available.

The International Convention for the Control and Management of Ships Ballast Water & Sediments is close to meeting the requirements for its entry into force. The terms of the convention attempted to force the development of the technology for treatment of ballast water, and a number of technologies have been developed, and systems using these technologies approved, to meet the convention’s requirements. Unfortunately, technological developments have not addressed the needs of certain vessel types, including those which must rapidly take on large volumes of ballast water for stability purposes such as semisubmersible drilling units and heavy-lift transport vessels. IADC continues to work to ensure that the needs of such vessels are recognized by the IMO and agreement reached on alternative measures that will allow these vessels to meet the requirements of the convention when it enters into force.

IMO has determined that it is appropriate to amend the SOLAS Convention to specify standards for onboard lifting appliances and winches. IADC has identified nearly 100 different classes of equipment that could be subjected to such standards, many of which are unique to drilling operations. IADC will be working to ensure that there is clear justification provided for the classes of equipment to be subjected to regulation, that there is clear identification of the equipment to be regulated and that the standards specified are appropriate.

IMO is developing requirements for periodic servicing and maintenance of lifeboats and rescue boats, launching appliances and release gear. Early drafts of these standards have limited the activities that can be carried out by shipboard personnel and required that other activities only be carried out by servicing facilities specifically qualified by the original equipment manufacturer. IADC is continuing to attempt to influence the final standards to avoid unwarranted burdens on rig owners.

IMO says no to oil spill liability regime for offshore oil and gas activities

At its 99th session on 16-20 April, the IMO’s Legal Committee considered a proposed change to the organization’s strategic direction to “focus on reducing and eliminating any adverse impact by shipping or by offshore oil exploration and exploitation activities on the environment.” This would be achieved by developing measures for mitigating the environmental impact of shipping incidents and operational pollution from ships, as well as liability and compensation issues related to transboundary pollution damage resulting from offshore oil exploration and exploitation.

The proposal resulted from an Indonesian-sponsored initiative proposing the establishment of an international liability and compensation regime for offshore oil and gas exploration and exploitation in the wake of the Montara incident. An amendment to the Strategic Directive was deemed necessary for the IMO to address the issue.

The text of a proposed amendment had been submitted to the IMO Council in 2011 but was returned to the Legal Committee for further consideration.

The debate was largely focused on two opposing positions: that of Indonesia, supporting the amendment, and one put forward by Brazil asserting that the IMO does not have a legal basis (within the UN Convention on the Law of the Sea or the International Maritime Organization Convention) for expanding its remit to address offshore oil and gas exploration and exploitation activities.

During the debate, which focused primarily on the proposed liability and compensation regime, numerous countries made oral interventions. As to be expected, most were somewhat circumspect and did not take a hard position.

IADC, represented by Mr Spackman, expressed the view that the proposal to revise the strategic direction could take the organization into a wholly new field of activities, including areas of design, construction and operation of offshore drilling units and support services, which would be well outside the scope of liability and compensation for transboundary pollution damage. If this is intended, then it should be made clear.

The committee agreed to inform the council that it wished to analyze further the liability and compensation issues connected with transboundary pollution damage resulting from offshore oil exploration and exploitation activities, with the aim of developing guidance to assist states interested in pursuing bilateral or regional arrangements without revising the strategic direction. The committee recognized that bilateral and regional arrangements were the most appropriate way to address this matter and that there was no compelling need to develop an international convention on this subject. Indonesia made it clear that it would continue to pursue this issue.

API to stop sending standards through ISO process

In the early 1990s, API and many of its members adopted the mantra of “Do it once, do it right, do it globally,” with the goal of transitioning API’s upstream oil and gas industry standards to international standards developed under the auspices of the ISO Technical Committee on Materials, Equipment and Offshore Structures for Petroleum, Petrochemical and Natural Gas Industries (TC 67).

This aspirational effort has come to a standstill, with API announcing that it will no longer send its standards through the ISO process. API’s decision reportedly stems from an inability to reach agreement with ISO regarding intellectual property rights, as well as concerns relating to US sanctions against Iran and Iranian participation in the ISO process.

“How this will affect the continued development of ISO standards remains to be seen, as many companies, both in the US and Europe, are taking a cautious approach toward participation in the ISO process due to the sanctions concerns,” Mr Spackman reported. “Further, the ISO standards development process has benefitted greatly from, if not relied upon, having API standards presented as core documents for further development into ISO standards, along with the direct participation of the industry experts that developed the API standards.”

API and OGP are participating with other stakeholders in developing a long-term plan for global standards development and it remains stated API’s objective to work towards one global standard.

“How the global standards development process will evolve in response to these challenges is not clear. Ultimately, it will be determined by the support of oil and gas exploration and production companies, service providers and equipment suppliers as they decide where their standards-development resources can best be applied,” Mr Spackman said. Nonetheless, many ISO standards activities continue.

ISO to develop site-specific assessment of floating units

ISO’s Offshore Structures Subcommittee (TC 67/SC 7) has approved a proposal for the development of a new standard ISO 19905-3, site-specific assessment of mobile offshore units – part 3: floating units. Experts were nominated by France, the US, the UK, Singapore, Canada, the Netherlands and Norway to develop the standard, which is targeted for publication in 2014. SC 7 also approved projects to update the standards for seismic design procedures (ISO 19901-2), geotechnical and foundation design (19901-4), and to develop a new standard on marine soil investigation (19901-8).

ISO subcommittee on arctic operations to be established

ISO’s Technical Committee 67 on materials, equipment and offshore structures for petroleum, petrochemical and natural gas industries has decided to establish a new subcommittee (SC 8) on arctic operations. Mikhail Rusakov, head of Gazprom’s offshore projects directorate, will chair the new ISO/TC 67/SC 8 Arctic Operations. The subcommittee will be responsible for the standardization of operations associated with exploration, production and processing of hydrocarbons in onshore and offshore arctic regions and other locations characterized by low ambient temperatures and the presence of ice, snow and/or permafrost.

The following ISO member bodies have expressed their intention to actively participate in the work of the subcommittee: Canada, France, the Netherlands, Norway, the Russian Federation and the US. IADC is requesting that it be granted liaison status with the new subcommittee. The first meeting is provisionally scheduled for April 2013 in Moscow. Companies interested in participating should contact their national standards organization.

Jackup site assessment standard published

After nearly two decades of effort, ISO 19905-1:2012 – Site-specific assessment of mobile offshore units – Part 1: Jackups has been finalized and is available from ISO, national standards bodies and various technical publications providers. The standard specifies requirements and guidance for the site-specific assessment of independent-leg jackup units. It addresses (1) manned non-evacuated, manned evacuated and unmanned jackups and (2) the installation phase at a specific site.

A related document, ISO/TR 19905-2 – Site-specific assessment of mobile offshore units – Part 2: Jackups commentary and detailed sample calculation, has passed ballot and should be available soon.

The IADC Jackup Rig Committee, which was formed to support the development of these ISO standards, will likely be continued to provide a forum in which technical issues associated with jackup site assessment can be discussed.

China to seek standard for offshore fixed platform modular drilling rigs

China has indicated that it will prepare a proposal for initiation of a new work effort at ISO for the development of a standard for fixed platform modular drilling rigs. China’s proposed work is based on existing Chinese standards. Based on the existing Chinese standards, ISO TC 67 has asked China to clarify how the standard or standards are to be organized and to address how any overlaps with the existing suite of ISO standards would be addressed. Singapore and Malaysia also expressed interest in this standard.

IADC comments on New Zealand HSE regulations revision

In August, IADC submitted comments to the New Zealand Department of Labour commenting on its review of the Health and Safety in Employment (Petroleum Exploration and Extraction) Regulations of 1999.

The letter, sent by Mr Spackman to the department’s Health and Safety Policy Unit, noted that IADC intends to assess its HSE Case Guidelines for MODUs against the revised New Zealand regulatory requirements when they are promulgated. The IADC guidelines will be revised as appropriate, with a new section to assist members in ensuring compliance.

Mr Spackman also emphasized that IADC and API are developing the Well Construction Interface Document to provide guidance on bridging the drilling contractor safety case to that of the operator. Although this targets operations in US jurisdiction, IADC is in the process of developing similar guidance for global applications.

IADC also provided detailed comments on specific sections of the New Zealand regulations revision relating to:

• Potential for major accident events;

• Duties to ensure the safety of wells, installations and activities carried out on installations;

• Promoting competence in persons carrying out well operations;

• Notification of well operations;

• Cooperation;

• Notification and reporting of dangerous occurrences;

• Workforce involvement in the preparation and revision of safety cases;

• Appropriate resourcing for safety case assessment;

• Revision of safety cases;

• Particulars to be included in safety case for installation; and

• Standards to be applied to petroleum operations.

OESC submits recommendations to DOI/BSEE

The Ocean Energy Safety Advisory Committee (OESC) has submitted its first formal recommendations to the US Department of the Interior (DOI) and BSEE. These recommendations included:

• Safety management system enhancement – Continued work on BSEE’s SEMS 2 rule should be focused on addressing four critical issues with the current SEMS regulations – jurisdiction, responsible party, performance-based approach and process safety management.

• Safety culture – DOI/BSEE should establish an Offshore Leadership Safety Council, including key representatives from regulatory bodies, industry and stakeholder organizations. The council’s role would be to:

- -Develop, communicate and foster a safety culture for the industry that provides a common value;

- Formulate a safety culture recognition program to motivate organizations;

- Encourage and incentivize engineering schools to include elements of safety engineering programs; and

- -Encourage industry to develop a structure for conducting consistently detailed accident and near-accident investigations and reporting them to the industry and regulators.

• Leadership and communication training – BSEE/DOI should work with the industry and the new council to develop leadership and communication safety training requirements.

• Workshop on organizational and systems readiness for containment response – A workshop should be developed to debrief government, industry and academic resources involved in Macondo to discuss lessons learned.

• Assessment and development of research priorities for containment of a non-capable blowout – DOI/BSEE should immediately begin synthesis of Macondo reports on organizational and system readiness pertaining to source control.

Don Jacobsen, Noble Drilling, is a member of the OESC.

IADC, BROA detail MLC 2006 implementation issues

IADC and the British Rig Owners Association (BROA) jointly responded to the UK’s Maritime and Coastguard Agency regarding the UK’s implementation of the Maritime Labour Convention, 2006 (MLC). IADC and BROA, the trade association for British owned and managed rigs operating on the UK continental shelf, wrote in support of prior comments submitted by the UK Chamber of Shipping and addressed potential impacts of MLC ratification and implementation within the UK. The joint letter included annexes that addressed:

• Crew accommodation regulations: Multiple occupancy cabins for crews are normal practice and are necessitated by the density of equipment and size of the work force. To change this in favor of single-occupancy cabins on new platforms is not feasible in all cases and may be prohibitively expensive. Also, specifications of ventilation system performance are beyond the scope of the MLC itself, and the excessive requirements should be removed.

• Food and catering regulations: Better guidance is needed on the use of chlorine and chloramine in water treatment. Further, the requirement for fresh water tanks to be emptied, inspected, cleaned and overhauled on a 12-month basis is considered excessive given the longevity of modern systems.

• Medical care regulations: The requirement to carry a doctor if more than 36 hrs of sailing time from a suitable port is not suited to MODUs, which are covered by other means of assistance and personnel transfer, such as helicopter services and standby vessels. Additionally, the liability of the shipowner for expenses related to a seafarer’s illness or injury should be constrained to that imposed by the MLC. The proposed wording of “any expense reasonably incurred” is too wide and will lead to inconsistent application.

• Shipowner liability – The MLC is specific about which shipowner is required to provide financial security, and the UK’s implementation should mirror that clarity.

• Other comments on MLC and MODU operations – International understanding of whether the flag or coastal State will have responsibility for: identification of competent authorities, enforcement responsibilities, employment agreements, control over wages and calculation of wages for work exceeding eight hours per day, hours of work and rest regulations, inspections and consultation. Also, obligations for repatriation to the country of residence should not be placed upon the shipowner for foreign nationals who have obtained authority to work in the coastal State, were hired in the coastal State and are governed by a labor agreement in the coastal State. It must be clear whether the coastal State will be willing/obligated to accept the manning levels established by the flag state.

IADC and BROA’s concerns, among others within those categories, are derived from the fact that MODUs are subject not only to their flag State’s maritime regulations and maritime enforcement but also to the laws of the nation on the continental shelf of which they operate. These regulations, in combination with the MLC, can create conflict between requirements of local land-based regulators and those of the MLC/flag State.

The IADC/BROA letter has also been forwarded to other national regulatory agencies that are beginning to develop their plans for implementing MLC in an effort to influence their development efforts.

Maritime Labour Convention to enter into force in August 2013

The International Labour Organization has announced that the Maritime Labour Convention 2006 has met the criteria for entry into force. On 20 August, it received its 30th ratification and, since the tonnage threshold had already been met, it will enter into force on 20 August 2013.

Intended as a “flag-State” instrument, it is IADC’s view that MLC is particularly ill-suited for application to MODUs, where the coastal States in which these units operate commonly extend their social and labor requirements to MODUs operating in areas under their jurisdiction and where large numbers of third-party personnel (who may be considered “seafarers” under the Convention) may be employed on board.

Working with members, IADC is pleased that many flag-States have determined that MODUs are excluded from MLC.  IADC will continue to work with other flag-States and coastal-States to assure that the status of MODUs under MLC is clearly understood and appropriately reflected in national regulations.

OSHA FRC rule struck down

An Administrative Law judge with the US Occupational Safety and Health Review Commission (OSHRC) struck down OSHA’s fire-resistant clothing (FRC) memorandum. The March 2010 enforcement directive to OSHA regional administrators and state plan designees purported to clarify OSHA policy for citing the general industry standard for personal protective equipment (PPE) for failure to provide and use FRC in oil and gas drilling and servicing operations.

The court found that the FRC memo constituted improper rulemaking. By using the terms “concludes” and “requires,” OSHA went beyond interpretation into the realm of rulemaking by converting a performance-based standard into a specific standard. Further, the court found that the memo does not have the force and effect of law. If OSHA wishes to require FRCs, the agency must resort to the required notice and comment rulemaking process. This is the position that IADC took in its letter to OSHA in April 2010 asking the agency to rescind the memo.

In November 2011, Mr Hurt and Kristin Hincke of the Association of Energy Service Companies (AESC) visited representatives of US House and Senate members regarding OSHA’s use of memos and interpretations to change or make regulations. Meeting with staff representatives of senators and congressmen, Mr Hurt highlighted the process OSHA used in changing the personal protective equipment rule (29 CFR 1910 132), particularly in regards to issuing its FRC letter of instruction to area directors. Other OSHA, EPA and DOT issues, where proper procedures were not followed, were discussed.

The visits were part of a joint effort with the AESC. All congressional staff representatives agreed with the IADC and AESC position and expressed support for sending a letter to OSHA requesting that the agency not attempt to change regulations through interpretations and directives. Texas Congressman John Culbertson, Kansas Congresswoman Lynn Jenkins and Louisiana Sen. Mary Landrieu have previously sent letters to OSHA expressing their concern with the process OSHA followed in regard to PPE regulations, specifically with FRC.

Federal Motor Carrier Safety Administration publishes final rule on cell phone use

The Federal Motor Carrier Safety Administration and the Pipeline and Hazardous Materials Safety Administration published a final rule in December 2011 to prohibit use of handheld mobile phones by commercial drivers while driving or on the road.

Under the final rule, driving refers to operating a motor vehicle on the road, including those that are temporarily stationary because of traffic, a traffic control device or other momentary delays. It does not include operating a commercial motor vehicle when the driver has moved the vehicle to the side of or off a highway and has halted in a location where the vehicle can safely remain stationary. The final rule does not ban the use of hands-free devices.

Drivers who violate the restriction can be charged a civil penalty of up to $2,750; a civil penalty of up to $11,000 can be imposed on employers who fail to require their drivers to comply. Additionally, motor carriers are prohibited from requiring or allowing drivers of CMVs to use handheld mobile telephones.

The agencies also amended regulations to implement new driver disqualification sanctions for CMV drivers who fail to comply with this federal restriction. Further, new driver disqualification sanctions restricting the use of handheld phones were implemented, applying to those who hold a commercial driver’s license and have multiple convictions for violating a state or local law or ordinance on motor vehicle traffic control.

NHTSA issues notice on voluntary driver distraction guidelines

The National Highway Traffic Safety Administration (NHTSA) issued a notice in 2012 on nonbinding, voluntary NHTSA Driver Distraction Guidelines. The notice details contents of the first phase of the guidelines, which covers original equipment in-vehicle device secondary tasks performed by the driver through visual-manual means. Such activities include communications, entertainment, information gathering and navigation tasks not required to drive.

The proposed guidelines list certain secondary, non-driving related tasks believed to interfere inherently with a driver’s ability to safely control the vehicle. Those in-vehicle devices are recommended to be designed so that they cannot be used by the driver while driving.

For all other secondary, non-driving-related visual-manual tasks, the guidelines specify a test method for measuring the impact of task performance on driving safety and time-based acceptance criteria for assessing whether a task interferes with driver attention too much. If a task does not meet the acceptance criteria, the guidelines recommend that in-vehicle devices be designed so that the task cannot be performed by the driver while driving.

OSHA HCS harmonized with UN standards

In March 2012, OSHA issued a final rule aligning its Hazard Communication Standard  (HCS) with the United Nations’ Globally Harmonized Systems of Classification and Labeling of Chemicals.

HCS requires chemical manufacturers and importers to evaluate the hazards of the chemicals they produce or import, as well as prepare labels and material safety data sheets to convey the hazards and associated protective measures to users of the chemicals.

The modifications include:

• Revised criteria for classification of chemical hazards;

• Revised labeling provisions, including requirements for the use of standardized signal words, pictograms, hazard statements and precautionary statements;

• A specified format for safety data sheets, revisions to definitions of terms used in the standard; and

• Requirements for employee training on labels and safety data sheets.

The rule became effective 25 May 2012.

Dunes sagebrush lizard protection status rejected

In June 2012, the US Fish and Wildlife Service made its final determination that the dunes sagebrush lizard does not warrant endangered status under the Endangered Species Act. IPAA president and CEO Barry Russell stated, “Sen. John Cornyn (R-TX), Sen. Jim Inhofe (R-OK), Rep. Steve Pearce (R-NM) and Rep. Mike Conaway (R-TX) have been instrumental in combating this listing, which would have been a death toll to jobs, energy and economic growth in these areas. After a year and a half of consideration, the Fish and Wildlife Service has made the right decision regarding the protection status of the dunes sagebrush lizard. The Interior Department’s decision affirms the fact that oil and natural gas development and environmental protection are not in opposition, as it recognizes the successful conservation efforts of regulators, nonprofit groups and industry working together at the state level.”

FMCSA seeks input on hours of service regulatory guidance

In the 5 June 2012 US Federal Register, the Federal Motor Carrier Safety Administration (FMCSA) announced its revision of regulatory guidance to clarify the applicability of the “oilfield operations” exceptions in 49 CFR 395.1(d) to the “Hours of Service of Drivers” regulations and requested comments on the revision. The regulatory guidance is being revised to ensure consistent understanding and application of the regulatory exceptions. To develop better understanding of the oilfield exception, FMCSA is seeking clarification on two questions:

• What does “servicing” of field operations of the natural gas and oil industry cover?

• What kinds of oilfield equipment may drivers operate while taking advantage of the special “waiting time” rule?

IADC solicited member input on how the rules would affect their operations and submitted comments to the docket.

OSHA seeks input on variance for ladders on rig derricks

In 1973, OSHA issued a temporary variance from 29 CFR 1910.27 for ladders on drilling rig derricks. The variance was obtained by IADC because although most parts of derrick ladders may meet the requirements of 1910.27, there are some ladders or parts of derrick ladders that do not. This temporary variance was issued to IADC and its listed members at the time.

OSHA recently realized that they had not followed up and made the variance permanent and is seeking input form IADC on the need for the variance.  Although IADC will seek a permanent variance for the drilling industry, all drilling contractors who wish to be included in the variance will have to complete an application for their company.

IADC is working to collect member applications for submission to OSHA.

Oil and gas multi-agency stakeholder meeting hosted by OSHA

OSHA, along with other agencies with jurisdiction for oil and gas operations both onshore and offshore (EPA, BSEE, USCG, DOT, PHMSA, BLM and BOEM) held a two-day public stakeholder meeting on 20 and 21 September at the College of the Mainland in Texas City to explore the use of management systems in the US. The interagency group asked for input from industry on the potential success/problems with a performance-based regulatory program as opposed to current prescriptive regulations. OSHA asked for industry input on such a change in the regulatory regime of the agencies. OSHA also sought input from industry regarding merging regulations across agencies.

Other US land operations initiatives:

• Participated in the creation of the OSHA 5810 Hazard Recognition and Standards Course for the upstream oil and gas industry;

• Participated and supported the National STEPS Networks throughout the continental US;

• Participated in the Oklahoma Safety Standdown sponsored by OSHA and the National STEPS Network;

• Participated on the Respirable Silica Focus Group;

• Participated on NIOSH’s NORA Council;

• Participated and supported various safety summits throughout the continental US; and

• Facilitated the Swamper Competency Guidelines through the Rig Moving Committee.

The Accreditation and Certification Department (ACD) kicked off an ambitious project to develop worldwide competency guidelines for virtually all rig positions, with Phase One priority on safety-critical positions with well control responsibilities. The guidelines, to be built upon IADC’s Knowledge, Skills and Abilities (KSA) templates, aim to provide tools for confirming the proficiency levels of the drilling work force, developing competence levels for new entrants and helping ensure that a globally accepted level of competency exists in the drilling industry.

“IADC is the global leader in developing competency and training programs for the drilling industry,” said 2012 IADC chairman Dan Rabun, chairman, president and CEO of Ensco. “This ambitious expansion of IADC’s KSAs represents a step-change for safety and competency in our industry.”

The project was launched with a workshop held at NASA’s Hi-Con Training Center in February 2012. More than 45 attendees representing 11 drilling contractor companies and nine operators convened to review the looming work force capabilities challenges facing the industry and discuss the vision for the KSA project. During two breakout sessions in which drilling contractors and operators met separately, Mr Denkowski and Dr Kelly facilitated discussions to gain better insight into member’s global needs for a common set of competence guidelines, and seek members’ guidance and direction for the project’s forward path. ACD staff also sought members’   commitment to ongoing participation in the project.

Both a steering committee and a review panel were established with representatives from IADC member companies. Further, Petrofac Training Services has been contracted to provide administrative and technical support of the project.

During the first of three planned phases for the project, IADC undertook a worldwide mapping of similar competency systems being used in other industries and even by governments to determine if there is an existing system structure that could be adapted for the drilling industry. Lessons learned from the organizations contributing to this effort helped assure that IADC’s competencies developed would be globally accepted. Approximately 10 to 15 positions are targeted in Phase One, including safety-critical positions with well control responsibilities such as driller, toolpusher and subsea engineer. This phase is expected to be complete by year-end or early 2013.

Phases Two and Three will target the remainder of rig-based positions, such as mechanic, electrician, roustabout, floorhand and derrickman.

Once released, the new guidelines will be open access, just like the original IADC KSA templates published in 2000. Those are still available online at the IADC website.

Well control training reviewed and strengthened

Strong emphasis on enhancing well control training has been a priority for ACD, with WellCAP accreditation requirements strengthened, curriculums revised or in revision, and an advisory panel formed.

WellCAP accreditation requirements changed

The amount of practical hands-on exercises and simulation for WellCAP courses was increased to at least 30% of the required course time, not including testing time. Prior to 2012, the activities could not exceed 30% of the course time. This change is expected to strengthen learners’ skills development and increase knowledge retention.

WellCAP program handbook revised

The WellCAP Handbook for Accreditation, Form WCT-01, was updated and revised, with all WellCAP accreditation criteria consolidated into one document. Other changes made to this version of the Handbook (Second Edition, Version 0) include:

• All program requirements previously published as bulletins, from Bulletin 04-02 to Bulletin 11-04, are now included in WCT-01.

• The WCT-01 document has been reorganized to more clearly delineate accreditation criteria, accreditation processes and accredited training providers’ responsibilities post-accreditation.

• Appendices have been added to list all WellCAP forms frequently used by accredited training providers and to provide an index of frequently asked questions, with referenced page numbers provided.

WellCAP curriculums revised

The supervisor-level WellCAP drilling curriculum was revised after months of intensive review, debate and discussion. The most notable changes were:

• Reorganization of the curriculum to focus on learning objectives;

• Addition of cased drilling and directional drilling topics;

• Removal of references to coiled tubing, wireline, snubbing and underbalanced operations as these operations are covered in separate curriculums; and

• Enhancement of the subsea module.

Equipment topics in the current curriculum were deemed adequate to meet industry’s basic needs. Course duration will not be impacted.

Other WellCAP courses under revision are the fundamental level drilling course and the underbalanced operations course (all levels). Both courses should be approved by end of year 2012.  In addition, a subsea curriculum module is being developed for the WellCAP Workover/Completion course.

WellCAP advisory panel formed

The WellCAP Advisory Panel was officially formed in March 2012 to drive continuous improvement of the IADC WellCAP accreditation program. This panel will provide strategic direction and policy guidance to IADC staff administering the WellCAP program. Current areas of review include:

• Training structure;

• Training content;

• Testing;

• Accreditation;

• Governance; and

• Achievement.

Members will also provide guidance on frequency of training, continuing education opportunities, instructor qualifications, and other issues relevant to the WellCAP program.

The 16-member panel will consist of IADC drilling contractor and operator members, chairmen of the Well Control, Training, and Well Servicing committees, and an IADC staff representative.

OOC award

Dr Kelly received a Recognition Award from the Offshore Operators Committee (OOC) for her contributions to the development of the Safety and Environmental Management Systems (SEMS) Toolkit, a collection of tools to help the US oil and gas industry respond to the new SEMS regulations. She led the Competence Subcommittee in the development of the Compliance Readiness Worksheet and the Knowledge and Skills Documentation Tool. She contributed to other SEMS tools and spoke at a series of toolkit rollout conferences across the US.

OOC chairperson Susan Hathcock, Anadarko, presented the recognition awards to 10 industry leaders “in recognition of (their) efforts and contributions in the development and rollout of a SEMS Toolkit to address consistency and compliance with new BOEMRE requirements and your effective networking with other industry representatives.” Other award recipients were Julia Swindle, IADC industry compliance specialist ; Milton Bell, ExxonMobil; Bill Walker, Cobalt International Energy; Troy Nugent, Baker Hughes; Greg Duncan, ConocoPhillips; Jeff Ostmeyer, Anadarko; Roger Molaison, BHP Billiton; Kim Parker, Hercules Offshore; and Ruth Rodriguez, Delmar.

New staff

Two employees joined ACD in 2012. Brooke Comeaux joined ACD as competence and learning development specialist, and Alma Roberts serves as accreditation and certification coordinator for the HSE Rig Pass program.

Ms Comeaux’s responsibilities include curriculum development and program upgrades of IADC’s various accreditation programs, competence program coordination, and new technology integration. Ms Roberts is primarily responsible for managing the IADC HSE Rig Pass program.

To expand the association’s global capabilities and increase support for regional chapters around the world, IADC has established an international development department dedicated to enhancing our worldwide service delivery. The association is aggressively working to establish new offices in key markets, adding to the existing network of representation in Europe, Middle East, Africa, Asia Pacific and Australia. Additional regional representatives will be brought onboard to help to identify member needs and facilitate provision of member services – a key delivery mechanism for IADC to enhance operational integrity as regional representatives will help to monitor, measure and improve performance by establishing a network of key member contacts with global operations responsibility.

For instance, in Brazil, IADC is aware that members urgently require support and representation, as other Brazilian oil associations do not focus on issues directly affecting drilling contractors. IADC is keen to engage with relevant regulatory bodies and act as an intermediary with drilling contractors operating in the region.

A comprehensive review is ongoing of how IADC can better engage with its chapters to drive member alignment on critical issues.

The international development department also will continue to serve as an internal IADC “connector” to coordinate the needs of members in specific regions with the global capabilities within IADC, such as accreditation and certification needs, regulatory concerns, technical inquiries, contract issues, etc.

EOF highlights offshore safety efforts

Offshore safety was the focus of discussions at the IADC European Operations Forum (EOF) meeting on 12 June in Barcelona, Spain, with several regional regulators providing updates on post-Macondo efforts.

Steve Walker of the UK HSE discussed the way his organization managed the media, the public and the government following the April 2010 Macondo incident, as well as adjustments that have been made to UK’s existing HSE regulations.

Jan de Jong of the Dutch State Supervision of Mines offered his division’s reaction to Macondo, highlighting the need for enhanced process safety and more skilled employees.

From the Norway Petroleum Safety Authority (PSA), Øivind Tuntland provided updates on the PSA’s work since Macondo, and Taf Powell, European Commission adviser, discussed the newly established EU Offshore Authorities Group, noting that their objectives have been set out as being an EU-wide forum for regulators in an advisory role; identifying and exchanging best practices for major hazard prevention and emergency preparedness; disseminating lessons learned from accident investigations; and facilitating rapid information exchange between national authorities and the commission.

Steve Cromar, ConocoPhillips, gave an overview of ongoing work of the Wells Expert Committee, where four task forces are working on a database of well control incidents; BOP reliability and technology development; human factors; and international standards.

Finally, Dr Brenda Kelly, IADC senior director of accreditation and certification, provided an update on the KSA project and invited drilling contractors to actively participate.

IADC visits Poland, assesses emerging shale gas market

Mr Hoffmark visited oil companies, suppliers and regulators in Krakow and Warsaw, Poland, in 2012 to collect information on shale gas development in the country and promote awareness of the IADC Critical Issues for Shale Europe 2013 Conference & Exhibition, 23-24 October in Warsaw.

Poland currently imports 98% of its oil from Russia, and its natural gas production of 3.5 billion cu meters per year is not enough to meet the total demand of 14.5 billion cu meters. The country has been in search of alternatives, such as shale gas and renewable energy, in an effort to increase energy independence.

The Polish Ministry of Environment has granted 112 concessions so far to several international oil companies, with the most positive traces of shale gas being found close to the Baltic Sea in the northern part of Poland. It is reported that six companies out of 11 are considering further development based on exploration results thus far.

The US Geological Survey forecasted in 2009 that Poland could hold approximately 3 trillion to 5 trillion cu meters of shale gas. The estimate has since been revised to 38 billion cu meters, although no certainty can be established until additional drilling has been carried out. A minimum of 200 wells are required to produce a more precise reserves estimate, but only 28 wells have been drilled so far.

One challenge is that the Polish government is still lacking clear guidelines on taxation, HSE requirements and ownership rights to shale gas discoveries. To address this, the government is negotiating two bills on taxation and technical issues such as HSE. The Ministries of Finance, Environment, Economy and Treasury are working out relevant legislation, and it remains to be seen when the work will be completed. Until then, oil companies working in Poland are still left with uncertainty.

Oil and Gas Denmark launched

Mr Hoffmark attended the 23 August launch of Oil and Gas Denmark, an industry association that represents Danish drilling contractors, oil companies and service companies. The new group, headed by managing director Martin Næsby, has four focus areas: development of the oil and gas sector, infrastructure, HSE and development of competency.

In attendance at the launch event was Martin Lidegaard, Danish minister of energy. His inauguration speech emphasized the importance of the Danish oil and gas industry, which contributes about 9% of the total Danish export. Denmark has been self-sufficient in oil and gas since 1991 and has been a net exporter of energy. In the next five years, US $8 billion is expected to be invested in exploration and development.

IADC SAPC Golf Tournament

More than 600 players participated in this year’s IADC Southern Arabian Peninsula Chapter (SAPC) Golf Tournament in Dubai, each playing two championship courses over the two-day competition.

The event was capped by an elaborate awards dinner followed by live entertainment. The evening event was attended by approximately 1,700 people.

Noble Corp hosts MEOF

Noble Drilling hosted an IADC Middle East Operations Forum (MEOF) meeting at the Emirates Golf Club in Dubai. Mr Geer conducted the meeting and reported on IADC events and activities with a focus on programs relevant to operations in the Middle East region. Mark Denkowski, IADC VP for accreditation and certification, provided a presentation to explain the programs that IADC is pursuing to assist members with training and competency.  A key element of his presentation focused on IADC’s KSA program.

IADC Nigeria holds meeting

The IADC Nigeria Chapter, established in 2011, held a meeting in October 2012.  The group, based in Lagos, is led by an Executive Committee consisting of Alex Illah from Transocean, Dr Olushola Ismail from Oando Energy Services, Ramoni Adeniji from Saipem Nigeria and Ben Agadaba of Lonestar Drilling.

AOF focuses on training, HSE questionnaires

IADC held its first Asia Operations Forum (AOF) meeting of 2012 on 24 April in Singapore to discuss regional training needs and other concerns for members in the Asia Pacific.

IADC VP of accreditation and certification Mark Denkowski kicked off the meeting with a presentation discussing the six IADC accreditation programs, as well as the accreditation process and new training-related projects that are under way.

That was followed by a roundtable discussion focusing on creating a comprehensive HSE questionnaire to be accepted as the standard safety questionnaire (SSQ) by operators in the Asia region and reviving the Southeast Asia Chapter and re-electing new officers.

On the first issue, it was agreed that a task group would be formed to develop a comprehensive HSE questionnaire template; it will be shared with operators for review and endorsement.

Members also expressed support for reviving the regional chapter. Upon identifying candidates to serve as officers, IADC will help coordinate a forum for an election and handover ceremony.

Another AOF was scheduled for 24 October in Singapore to discuss international standards activities affecting the offshore oil and gas industries and other critical issues for members in the Asia Pacific region.

A special guest presentation on QHSE management will be shared by RPS, and IADC will update members with the various conferences, activities and initiatives in the region and globally.

As with the customary AOF meetings, an open group discussion will be made on other key regional issues raised at the meeting, including the prospect of reviving the Southeast Asia Chapter. There is a necessity to appoint new officers to lead the chapter again in the region.

IADC attends PETRONAS launch of competence development program

PETRONAS Carigali’s Drilling Division launched its Capability Development Journey, an in-house structured competence development program, on 9 March in Kuala Lumpur. The approximately four-year program covers the fundamentals of exploration and production, petroleum engineering, drilling courses, WellCAP-accredited well control courses, and HSE-related courses, including offshore survival.

Offshore trips are incorporated into the curriculum for on-the-job training. Trainees’ time offshore is increased as they gain hands-on experience. Upon passing all courses, a final exam determines the type of job for which the engineer is most suited.

IADC attended the ceremony along with representatives from companies such as Baker Hughes, Halliburton, INSTEP, Schlumberger, Uzma and Weatherford. Datuk George Ling, adviser for the PETRONAS Drilling Division, provided the opening remarks, and Hj Zulkarnain Ismail, head of the division, recorded appreciation for the support of human resource management, technology and information management and technical capability management.

A handover ceremony was held between the Drilling Division and various companies, including reference materials such as IADC textbooks, the Schlumberger Field Data Handbook, Halliburton Red Book and Uzma Garraf Drilling Manuals.

PETRONAS will conduct its well control training through Transocean’s recently launched Kuala Lumpur facility. INSTEP, a PETRONAS subsidiary, will serve as training coordinator.

Indonesian local content workshop planned

IADC held a workshop for its drilling contractor members on  “Prioritizing the Utilization of Domestic Goods and Services in the Upstream Oil & Gas Industry in Indonesia” based on Indonesia’s amended Procurement Working Procedure Manual PTK 007/Rev.2/I/2011.

IADC members, including Ensco, Nabors Drilling, Noble Drilling, Northern Offshore, Rowan Companies, Songa Offshore and Vantage Drilling, attended the one-day session on 25 October at the Hilton Hotel in Singapore.

PT Patra Mitra Konsulindo, an Indonesian consulting firm, helped conduct the training covering the legal aspects, basic principles and amendments made of local content calculation on procurement of materials, goods and services and how to properly prepare rig service cost structures and fill in local content in bid documents.

Business groups seek detailed FCPA guidance

IADC wrote to the US Department of Justice (DOJ) and the Securities and Exchange Commission (SEC) to request that specific issues be addressed in detailed new guidance expected this year on the criminal and civil enforcement provisions of the Foreign Corrupt Practices Act (FCPA). The letter was signed by more than 30 business groups, including the National Association of Manufacturers, the National Foreign Trade Council and the US Chamber of Commerce.

A key issue is that, although the FCPA prohibits corrupt payments or offers of payments to foreign officials, there is not adequate guidance on who is a “foreign official.” A clear, uniform definition of “instrumentality” is needed so companies may conform their conduct. The letter also addressed a concern that sufficient consideration may not be given to potential defendant companies’ strong, pre-existing compliance programs when making enforcement decisions. Guidance is needed on what would be considered an effective FCPA compliance program that would merit favorable consideration in enforcement decisions.

Further, the FCPA does not set forth circumstances when a parent company may be held liable for a foreign subsidiary’s violations. This lack of statutory clarity is compounded by an apparent difference in enforcement policy between the DOJ and SEC, the groups noted. The letter detailed concerns with several additional key issues, including successor liability, gifts and hospitality, corporate criminal liability and other recurring issues.

IADC meets with DOJ, SEC

Noble Drilling Services’ James Sanislow, chairman of the IADC Ethics Committee, participated on behalf of IADC in a roundtable discussion on the FCPA with the US DOJ and the SEC. The event took place 11 April in Washington, DC, hosted by the US Chamber of Commerce Institute for Legal Reform.

Assistant Attorney General Lanny Breuer, SEC enforcement director Robert Khuzami and Commerce Department general counsel Cameron Kerry joined IADC and leading business community representatives for a discussion of the forthcoming guidance on FCPA enforcement.

At the forefront was the uncertainty that many US businesses face with the FCPA. Participants provided background on complexities in compliance and risk management arising from issues such as a lack of clarity around the definition of a “foreign official” and successor liability.

Mr Breuer and Mr Khuzami expressed appreciation for industry input in helping shape what they hope will be effective guidance. They also indicated that the agencies could release guidelines by late spring.

The IADC Ethics Committee is set to have its final meeting of 2012 on 12 December at IADC’s Houston office.

Erik Hoover, operations manager for Statoil, speaks at the 2012 IADC Drilling Onshore Conference and Exhibition on 17 May in Houston, Texas.

Eric Pena (from left), Hess; Stephen Prihoda, Marathon; and Mike Haas, Chevron, attend the IADC KSA workshop in February at the NASA Hi-Con Training Center.

Gregers Kudsk, VP technical management, Maersk Drilling, speaks at the IADC World Drilling 2012 Conference in Barcelona, Spain, on 13 June. Mr Kudsk made a presentation on state-of-the-art drilling systems automation.

Arun Karle (from left), Askara; Anup Kumar (partially visible), R.V. Marathe, M.D. Joshi and A.K. Hazarika, all with ONGC; Ken Fischer, IADC; Norman Edwards, consultant; and Chit Hlaing, IADC, participate in the 2012 ONGC-IADC workshop focusing on safey in drilling operations on 29 August in Mumbai.

By Joanne Liou, editorial coordinator

Although the US land rig count has steadily dropped throughout the year since Q1 and US natural gas prices have remained disappointingly weak, analysts are voicing optimism about a recovery in 2013 – looking to upticks in both rig demand and natural gas pricing. The offshore market is providing more signs for a positive outlook as well, powered by the deepwater Golden Triangle and a robust jackup market.

James Wicklund, Credit Suisse

Michael LaMotte, Guggenheim Securities

Onshore, the disparity between oil and natural gas prices persisted in 2012, from averages hovering around $96/bbl for oil to $2.50/Mcf for natural gas, according to Guggenheim Securities. “The last 12 months has been about transition,” Michael LaMotte, managing director, head of energy, Guggenheim Securities, said. “In terms of rig count mix, there has been a radical shift away from dry gas into gas liquids and oil.” Rig counts in gassier basins, such as the Haynesville, Marcellus and Barnett, have recorded sharp drops, whereas wetter areas like the Eagle Ford and the Permian Basin have come up significantly.

Offshore, the Golden Triangle – Brazil, the US Gulf of Mexico (GOM) and West Africa – continues to illuminate the deepwater scene, with additional discoveries in East Africa building opportunities for more activity in the coming year. “Five years ago, we didn’t think there was any hydrocarbons of commercial accumulations in East Africa,” James Wicklund, managing director at Credit Suisse, explained. “Anadarko and others have made some significant discoveries in East Africa, which has opened up that area as a brand-new play.”

John Spears, Spears and Associates

Sven Ziegler, RS Platou

On the equipment side, improved features in safety, efficiency and capability have ignited a phasing out of older rigs as contractors continue to invest in a fleet of modern newbuilds. “If you take the jackup market, for example, the market has tightened with increased utilization, but nonetheless, we’ve seen more scraping this year than before,” Sven Ziegler, head of offshore research, RS Platou, stated. “One doesn’t really scrap or remove units in an improving market unless the units are very much subcondition.”

Moving into the new year, some analysts believe operators will continue to plan their activities given the disparity between higher oil prices and lower natural gas prices in the US. “Operators will probably be budgeting their drilling programs assuming oil prices will be about $80 and gas prices will be around $3,” John Spears, president, Spears and Associates, said. “They will be very conservative in their price estimates for both those commodities, which will mean that their drilling budgets for the coming year will be very little changed from what they’ll be spending this year.”

Analysts at Guggenheim Securities project natural gas prices will recover in 2013 by about 57%. Well counts are on the rise in the deepwater and ultra-deepwater markets as well, with activity still focused in the Golden Triangle. Source: PFC Energy-Guggenheim Price Forecast.

Commodity prices

For operators, a main driver of the drilling business is the income of the asset, which in 2012 has been leading them to shift drilling programs across the US away from gas toward oil. Although natural gas prices in 2012 are expected to be down 30% year-over-year – from $4.03/Mcf in 2011 to $2.82/Mcf in 2012 – Guggenheim Securities is considerably more positive on gas prices for 2013, which the firm believes will be north of $5/Mcf at the end of next year with an average of $4.42/Mcf – an increase of 57%.

Mr Spears believes natural gas prices in the US will rise because of the high chances of a more normal winter. The 2011 to 2012 winter was unseasonably warm in much of the US, leading to a lack of demand for natural gas to keep homes and businesses warm. “If we have a normal winter, there will be normal amounts of gas in storage that won’t be depressant on the market like it has been this year,” Mr Spears explained.

“Since rig activity has fallen so far in the number of new gas wells being drilled – it’s fewer than 10,000 wells right now – that puts some constraints on the supply of gas, so we think there will be some increase, small increase, in gas use next year.” The combination of low levels of natural gas drilling activity with the potential increase of gas use is establishing conditions for gas prices to recover some.

George Littell, Groppe, Long & Littell

While natural gas prices experienced a steady decrease throughout the year, oil prices have fluctuated, going as high as $106/bbl in May to as low as $77.70/bbl in June. “They’ve ranged a lot, but we think they will end up averaging $94.50 this year, which is almost no change from the price we saw last year for spot oil prices,” Mr Spears said. Although prices might continue to fluctuate in the coming year, he expects the average to stay around $95 in 2013. “That kind of volatility is a fact of life in the commodity market,” he stated. “We just have to hold on for the ride.”

The disparity between gas and oil prices recorded in the US also applies to the global market. Crude oil sits around $18 per million Btu, about $108/bbl, while natural gas prices are down between $8.50 and $12 per million Btu ($51 and $72/bbl), according to George Littell, partner at Groppe, Long & Littell. “For the US, the odds are pretty good that the disparity will narrow quite a bit during 2013, but it won’t disappear. Gas prices have been so depressed; they’re liable to come up substantially.” Likewise, more normal weather and stable to declining gas production will help gas prices increase. “Production has been flat in 2012, and we see between a 1% to 2% decline for 2013,” he added.

Guggenheim Securities charts a flat forecast for jackup supply in 2013, while the supply of floaters will slightly increase. Industry is experiencing a healthy utilization rate for both jackups and floaters, a trend that will likely continue in 2013. Source: Guggenheim Securities.

Rig counts

When crude oil prices started declining in early May, the oil rig count in the US started to decline fairly significantly as well, Mr Wicklund of Credit Suisse described. Drilling activity in oil-prone areas onshore US has continued to improve along with oil prices. In Q4 2011, Spears and Associates recorded 1,130 rigs drilling for oil and 880 rigs drilling for gas in the US, whereas they project Q4 2012 to finish with 1,451 rigs for oil and 441 rigs for gas. The overall US rig count for 2012 will be slightly up by 4% from 2011, according to both Credit Suisse and Spears and Associates.

At the end of September, the US land rig count stood at 1,808, down from 1,946 one year ago, according to Baker Hughes’ rotary rig count. The US rig count, including both land and offshore, peaked in Q1 with 2,008 in January and has been falling since then.

While Mr Wicklund expects the US land rig count to be fairly close to flat this year, footage for US land rigs is up 25%, a positive indication for revenue of service companies and drilling contractors. The number of rigs working is not increasing by much, he said, but the jump in total footage shows that rigs are staying on location longer with fewer moves. “We expect the rig count to be flat to down through the rest of this year and to make its usual seasonal drop for the first three or so months into 2013 before we start getting some clarity on commodity prices. (Once) we get more confidence in the outlook in the economy, we’re actually looking at the rig count to rebound in the last eight months of next year.”

In 2013, Spears and Associates expect an average 1,950 land rig count in the US, with about 1,500 dedicated to oil and 450 for gas.

Mr Littell shared similar sentiments in the US rig count outlook. He forecasts gas-directed drilling in 2013 will be down to 300 rigs, while the oil rig count will fall between 1,600 and 1,700 rigs. “My 300 gas-directed rig count assumes there is some recovery in prices,” he said.

Nearly 300 jackups of the global fleet’s 477 were built before 1984, according to RS Platou. More newbuild floaters and jackups are scheduled to enter the market, as a removal trend of older assets has begun. Source: Guggenheim Securities.

The distribution of land rigs drilling for gas versus oil reflects lower gas prices and healthier oil prices. In Q4 2011, the Marcellus rig count was 155, while the Permian rig count was 455; the projected rig count for Q4 2012 is down to 100 in the Marcellus and up to 480 in the Permian, according to Guggenheim Securities.

Globally, the total rig count outside the US is also expected to slightly increase. Mr Wicklund projects a 2.3% increase to about 1,193 rigs, excluding Iraq, in 2012, which falls in line with the 20-year average. “We’re looking at 1% growth in the rig count in 2013, with virtually all that growth being in the offshore, primarily deepwater market,” he said.

Rig counts continue to reflect North America’s shift away from shale gas to shale oil – from dryer gas basins like the Haynesville to more oil-rich basins like the Eagle Ford. Analysts forecast rig counts to fall in the next six months before stabilizing in 2013. Although rig counts have declined and gas prices have remained low, 2012 domestic gas production is expected to be up about 4% from 2011, according to Spears and Associates. Source: Guggenheim Securities.

Currently, gas drilling accounts for 25% of rig activity in the US, while it accounted for 32% in 2011 and 70% in 2009. “There has been a huge shift from gas drilling in the US to oil drilling,” Mr Wicklund explained, “starting about three years ago when the shale oil development started moving and gas prices started to drop.

“We have grown oil production by several hundred thousand barrels in each of the last couple of years. It is expected that we will continue to increase our oil production at a faster rate than any other country in the world and continue to do so over the next several years,” he continued. The possibility to reach US energy independence may not be 100%, but going forward, dependence on crude oil is expected to become less and less, he explained.

Pinpointing areas of growth, almost all of the gain in US oil production is from shale oil. North Dakota’s Bakken Shale is leading in the most gains, Mr Spears stated, while liquid from other shales in the mid-continent area and in West Texas are also contributing to the gains in production. On the other hand, results from the Utica Shale in the Ohio and Pennsylvania areas have not been as productive, but “that’s probably a couple of years down the road before we see any material increase in shale oil production from that neck of the woods.”

Despite low natural gas prices, as well as declining gas rig counts, Mr Spears expects US gas production to be up about 4% from 2011. “We’ve seen gas production increase, but next year, we’ll see gas production flatten and expect no change from 2012,” he stated.

While rig demand is up worldwide, Sven Ziegler of RS Platou noted demand for jackups in particular has been on the rise in Southeast Asia and the Middle East, and the trend is likely to continue. Source: RS Platou.

Drilling activity in the GOM continues to improve as the pace of permitting picks up after the 2010 moratorium. For this year, the average rig count offshore will fall around 47 rigs, according to Spears and Associates. Next year’s rig count is projected to grow to 53, a 12% increase. “From a percentage standpoint it looks pretty good, but it’s just a handful of rigs. That’s movement in the right direction,” Mr Spears stated.

The increase in rigs is expected to stem heavily from the deepwater market, as the shallow-water market in the GOM is primarily driven by gas prices. Credit Suisse’s forecast is even more promising for the GOM, as their analyst expects eight to 15 deepwater additions in the next 18 months.

Outside the GOM, the global offshore market continues its ramp-up as well, as reflected in rig counts and newbuild constructions. In 2010, there were approximately 50 drillships worldwide. By the end of 2012, the rig count is expected to more than double to 110, Mr Wicklund said. Further, he expects a sizeable increase in the number of highly capable sixth-generation semisubmersibles from 185 to 220 in 2013. “On a percentage basis, the increase in the number of ultra-deepwater rigs has dwarfed the growth in any other segment of business,” he noted. The bulk of deepwater rigs are set to drill in the Golden Triangle, but East Africa and other parts of South America, such as Suriname, are presenting new prospects for deepwater drilling as well.

Analysts are bullish about deepwater activity in 2013, with more deepwater hot spots emerging globally. Presalt plays offshore Angola and the African east coast, for example, are expected to increase demand for floating rigs. Petrobras alone has ordered 26 drillships and seven semisubmersibles in the past two years. Source: RS Platou.

Worldwide, utilization rates, as well as dayrates, have been moving in one direction – up. Modern units are being fully utilized, and the utilization rate for jackups is currently at 95%, Mr Ziegler of RS Platou said. “When it comes to floaters, it’s basically the same story – a very high utilization rate, but that’s backed up by a solid backlog. If you take ultra-deepwater dayrates, they moved up around 50%, since they bottomed in 2011,” he stated.

The difference between modern and older assets is becoming more visible. The distinction has always existed; however, the phasing-out of the older jackups has not occurred until this year, Mr Ziegler explained.

With a total fleet of 477 jackups, nearly 300 units were built before 1984, according to RS Platou. “We’re starting to see a removal trend become more and more prevalent,” Mr Ziegler said. “Inevitably the older assets have to be removed. The requirements to drill offshore wells are becoming increasingly complex. That means oil and gas companies need modern, high-specification assets, which are capable of that.”

The uncertainty and less-than-ideal capital markets have made financing difficult and pose an unfavorable environment for speculative rig orders. In September, RS Platou recorded 15 jackups ordered so far in 2012, while 2011 had a total of 45 jackups ordered. In 2013, 46 jackups are expected to be delivered, Mr Ziegler noted.

Considering that the historical growth rate of global jackup demand is close to 2% a year and the market is expecting 10% jackup fleet growth before scrapping and removals in 2013, Mr Ziegler believes either the market will decline and/or quite a few units will be removed.

“This uncertainty combined with lack of financing has really stopped the ordering activity,” he said. “The uncertainty has to be removed before the rigs start to be ordered again. It’s difficult because you have a market right now that is very strong and that should really lead to more orders.”

In 2011, 35 drillships and six semisubmersibles were ordered while 36 drillships and 13 semisubmersibles have been ordered this year, Mr Ziegler said. Of this year’s orders and last year’s, 26 drillships and seven semis will be going to Petrobras’ domestic program, with deliveries scheduled between 2016 and 2019.

Petrobras’ fleet and activity will crowd out international units while creating a competitive international industry of their own, Mr Ziegler said. “They’re the dominant player in Brazil, and the question is whether they can manage the situation for the growth.”

Rig utilization for floaters remained above 90% throughout 2012, according to RS Platou, while jackups also stayed above 90% for most of the year. Analysts believe the offshore rig market will continue to experience high utilization rates through 2013. Source: RS Platou.

Demand for jackups has been rising and will most likely continue to rise from the Southeast Asia and Middle East regions, Mr Ziegler noted.

Mr LaMotte of Guggenheim Securities is very bullish on deepwater activity in 2013 and 2014. For instance, in the GOM, he believes exploration and development spending will double between 2012 and 2014, due to a near tripling of exploration expenditures. By the end of 2014, Mr LaMotte expects the deepwater (3,000 ft or more) rig count to be at 56, up from the current working count of 30.

Exploration successes in the presalt horizons offshore Angola and the east coast of Africa are also expected to stimulate demand for floating rigs. “From a technical standpoint, the industry is dealing with the dual challenges of extreme drilling depths and extreme water depths in many of the emerging provinces,” Mr LaMotte noted. “However, the combination of high oil and LNG prices and the size of the resources discovered make for very competitive economics.”

Beyond deepwater, “the number of hot spots for ultra-deepwater is increasing globally,” Mr Ziegler stated. “Also, there’s fragmentation of the number of oil and gas companies, not only the majors, but there’s also fragmentation on the rig owner side.”

The unconventional resource potential has been identified but has not been investigated thoroughly in many places, such as China, Argentina, Poland, Australia and Saudi Arabia, which are considered the top five non-North American resource spaces, according to Mr LaMotte. “Over the long term, we are bullish on the shale markets of Saudi Arabia, Argentina and China, as these countries have tremendous needs for domestically sourced gas; however, development is likely to be much slower than it was in the US, as none of these countries have the ecosystem of the US to foster rapid exploitation – private landownership, a large and pre-existing oil services industry and open capital markets.”

Over the last few years, natural gas has become a far more important commodity internationally, due to robust demand, strong prices and accessibility, and it is a key theme in the coming year for the Middle East and Asia Pacific regions. From an oil services standpoint, Saudi Arabia and Australia are the key markets to watch, Mr LaMotte told Drilling Contractor. As Saudi Aramco tenders for more rigs as part of its strategy to spend $9 billion between 2011 and 2016 to add 50 Tcf of new, non-associated gas reserves and 5 Bcf/day of production, the ramp-up in tight- and shale-gas activity is comparable to the early days of the crude capacity experienced in 2004 to 2009, he stated in a September report about Saudi Arabia.

About half of the projected production has been identified and will come from the Karan, Arabiyah and Habsah fields. According to Guggenheim Securities’ report, Mr LaMotte expects the other half to come from the tight reservoirs of the deep Khuff, from the South Rub al Khali tight-gas discovery near the Shaybah field, and shale gas in the northwest province. Saudi Aramco had five rigs exploring for shale gas at the start of 2012 and has increased activity to about 12 rigs. The report states that the company is in the process of tendering for 20 rigs for 2013 and is considering an additional 20 rigs. By early 2014, total rig count in Saudi Arabia could reach 170, up from about 130 rigs presently working.

As Australia’s offshore LNG projects ramp up in the next few years, Mr LaMotte expects the demand for floaters to increase from 11 in 2012 to 25 in 2014. He also noted that the coal bed methane to liquefied natural gas projects in Queensland, Australia, will require at least 100 more rigs; however, the shallow nature of these wells suggest that the demand should be met by local contractors. “These are simple wells,” Mr LaMotte said. “It is truly post-hole drilling, so the technological differentiation offered by Western contractors is not a source of competitive advantage.”

The Vaca Muerta shale in Argentina presents a large amount of potential in a working environment without the typical challenges other regions face. “Surface rights issues are not really a problem, and they have an existing services infrastructure,” Mr LaMotte stated. “However, supply chain issues – many of which are exacerbated by government policy – are likely to be Argentina’s greatest impediment to the development of the Vaca Muerta.” In places such as Europe, where governments control the mineral rights and property owners control surface rights, he expects little progress to be made in the coming year.

In China, Shell expects to start its first commercial shale gas development program in a couple of years, according to Mr Spears of Spears and Associates. The company’s joint venture (JV) with China National Petroleum Corp (CNPC) has initiated exploration and appraisal drilling and in two year expects to start development drilling, he said. Hess also has announced a JV with CNPC for shale exploration. “The shale gas side of things is moving right along, and China has a prospect for being an shale oil area as well,” Mr Spears said.

Across the board, markets outside North America still lack the service industry and infrastructure necessary for large-scale unconventional development. “Rigs and pressure-pumping equipment are probably the biggest two items that, from a supply standpoint, seem to be lacking,” Mr Spears said.

Another key ingredient to move forward is the market price for gas. Oftentimes, whether the government will allow operators to realize a market price for the gas they produce is negotiated between an operator and the government, Mr Spears explained.

Since most unconventional shale drilling is in the exploration and appraisal stage, Mr Spears does not expect major progress to be made until operators understand the technical characteristics of the field and can use that to then consider commercial development, perhaps by the end of 2013.

US operators will spend close to $150 billion this year to drill and complete wells onshore US, and next year the amount will be around $147 billion, Mr Spears said. He believes spending will be less as a result of projected lower well costs.

Many analysts agree that deepwater exploration will continue to attract the most E&P dollars. Now that companies are breaking ground in Africa and Latin America, exploration has really become worldwide, Mr Littell said.

Mr LaMotte believes deepwater exploration will drive the bulk of spending growth next year and will increase to 30% in 2013. “Deepwater development is not far behind, with an 18% to 20% increase,” he said. He expects spending on unconventionals in the US to be modestly down next year, as a result of lower average rig counts and the deflationary effects of lower frac cost and lower rig rates. However, productivity gains suggests that completions volumes could be relatively flat. “The total number of completions is likely to be flat to down within 3%,” he said.

Analysts are counting on a more normal winter for the 2012 to 2013 season and stable to declining gas production to help boost gas prices in 2013. Although the number of active rigs in the US has been declining since the beginning of 2012, Spears and Associates’ 2013 forecast reflects a positive outlook for active rigs drilling for both oil and gas. Sources: Bloomberg; Natural Gas Week; Baker Hughes; Spears and Associates.

Onshore well costs are falling, with fracturing costs in particular helping to keep prices down. The average cost of drilling a well has fallen about 5%, and the cost of drilling is expected to continue to decline for about four more quarters before possibly stabilizing, Mr Spears said. “Much of that decrease in well cost has come about because of the lower cost of fracking a well. For the next three to four quarters, we’ll probably see land rig rates get softer,” he said, adding that it would not come as a surprise if rig rates were down about 4% in 2013.

“Frac costs were rising right up until January, and since then, they’ve dropped sharply. As a whole, we’ll see frac cost down about 15%, but there are instances we heard about where frac costs have fallen as much as 30%,” Mr Spears stated. Further down the road, Mr Spears believes it will be 2014 before the market is in a decent shape to support any increase in costs.

Analysts foresee companies taking caution in 2013. Mr Spears forecasts most of the capital spending by drilling contractors will be toward maintenance and replacement-type purposes until 2014 or beyond.

Mr LaMotte believes more consolidation is needed in the onshore US services market, moving from a phase that  addressed a capacity shortage in services through the construction of rigs.

“We’ve been through the period of ‘shock and awe,’ during which the industry tossed hundreds of billions of dollars at the near-simultaneous identification and early development of the largest unconventional gas and liquids plays in the Lower 48; however, with more than 70% of the nation’s resource potential in a more mature ‘standardization’ phase, we believe E&P companies will become increasingly focused on the productivity of their spending as opposed to just spending more,” Mr LaMotte explained. “It will require the industry to focus on reducing the cost of services delivery, on efficiency and on developing technologies that improve the recovery factors.”

Lessons learned along the way and the changing scene of the industry is raising expectations. “Operating offshore isn’t just about building the equipment and showing up either; success is now about demonstrating operational excellence through the training and retention of personnel, health, safety and environmental practices, and globalizing best practices. It’s going to require – quite simply – working smarter.”

Shell’s Prelude floating LNG project off the northwest coast of Australia is expected to begin production in 2017. In the next few years, projects in Australia that are expected to come online will put the country on par with Qatar in terms of export volumes. In 2011, Qatar led the industry in LNG exports with about 77 million tons.

No direct impact yet, but growing export expectations could encourage North American gas drilling

By Joanne Liou, editorial coordinator

Reviews of the 2012 drilling year reflect the continuation of low North American natural gas prices of $2.50/Mcf to $3.50/Mcf, which is causing a shift from gas drilling to oil drilling. However, on the other end of the forecast spectrum, the prospects of an emerging and growing liquefied natural gas (LNG) export market coupled with increased domestic gas demand could boost gas-directed drilling across North America. Bill Gwozd, senior vice president, gas services, Ziff Energy Group, believes the growth of LNG export markets around the world are encouraging additional drilling activity across North America.

Another unconventional strategy is the pursuit of gas-to-

James Wicklund, Credit Suisse

Bill Gwozd, Ziff Energy Group

liquid (GTL) technology that converts natural gas to liquid form, increasing opportunities to utilize the resource and therefore accelerate additional gas drilling. Companies have the ability to take surplus natural gas and convert it to diesel by using GTL, Mr Gwozd said. The process is economical, he said, proven and under way in several plants worldwide. Additional plants have been proposed for Louisiana and near Edmonton in northern Canada.

“The benefit here is the low price of natural gas as a feedstock for the GTL process, and that diesel is marketed at a high price that is comparable to oil prices.”

Although LNG may not be directly impacting the North American drilling activity yet, companies might consider the potential revenues that could be realized once US LNG facilities come online. “If (LNG) has done anything, it has slowed drilling in places like the Haynesville because the fear has been that a lot of these companies would pass their peak production before a facility was opened,” James Wicklund, managing director at Credit Suisse, explained. “They would have produced the bulk of their natural gas before a better market came along.”

Compounding that fear with already low natural gas prices, some companies are drilling just enough to hold acreage  while hoping for a better market in the future, he noted.

Low natural gas prices remain a concern for companies with operations in Canada as well. EOG Resources and Apache Corp, among other companies, are looking to build an LNG facility in western British Columbia, where the Horne River formation would supply the facility with natural gas for liquefaction for export to Japan and other areas in the eastern hemisphere. However, natural gas prices have dropped so dramatically that the economic break-even of the play is estimated to be $6 to $7, Mr Wicklund said. Companies are hoping that by the time the LNG facilities come online, natural gas prices will have risen enough to profitable, he added.

Although North America’s natural gas prices are the lowest globally, Rice University’s Baker Institute analysis believes there would not be enough profit margin to support long-term LNG exports from the US Gulf Coast to the UK or Japan. Source: Rice University study “US LNG Exports: Truth and Consequence.”

LNG facilities

The surge in shale gas production, aided by hydraulic fracturing technologies, has rerouted North America’s energy road map. Nearly a decade ago, the US began to invest in LNG terminals with the intention of importing the precious resource. Fast forward to present day, and many of those facilities sit idle with proposals to retrofit them for the exact opposite purpose: to export LNG. North America has 11 LNG terminals, including one in Puerto Rico, according to the US Federal Energy Regulatory Commission (FERC).

“The plan was for the US to become a major importer, but then shale happened and sort of turned the card upside down,” said Kenneth Medlock III, an adjunct professor and lecturer of economics and senior director at Rice University’s Center for Energy Studies at the James A. Baker III Institute for Public Policy. “Shale happened as we were building a lot of import

Kenneth Medlock III, Rice University

infrastructure, and it all sits idle now, which is where all this interest to turn those facilities around comes from because you want to make use of idle capital.”

LNG, the liquid form of natural gas, predominantly as methane, occupies about 600 times less space than natural gas when chilled to about -260°F (-162°C). The properties of LNG allow it to be stored in specially designed tanks and transported to distant markets, where LNG can be regasified and utilized as a source of energy. “With countries like Japan, Italy and Germany turning against nuclear to generate electricity and the world being increasingly concerned about pollution, natural gas demand is expected to grow for the foreseeable future globally,” Mr Wicklund stated.

The growing global LNG market reached 241.5 million tons in 2011, with a sharp increase from Japan by 8.2 million tons, according to the International Gas Union’s 2011 LNG Report.

With Japan and South Korea being the main consumers, “the market right now is not that large; you have a number of different exporting countries meeting that demand,” said Mr Medlock, who is also a James A Baker III and Susan G Baker fellow in energy and resource economics at Rice University. However, the market is bound to change as more markets, such as China and India, position themselves to import more LNG and more exporting countries enter the market or expand demand.

Qatar has emerged as one of the top LNG exporters on the international level within the last few years, exporting about 77 million tons of LNG in 2011. Other Middle Eastern countries exporting LNG include Oman, United Arab Emirates and Yemen. Out of Africa, Algeria, Nigeria and Egypt are exporting, and there has been discussion about countries such as Equatorial Guinea and Angola, Mr Medlock noted. Further into the eastern hemisphere, Russia is exporting out of Sakhalin Island, and Papua New Guinea will be on the map soon with the PNG LNG project with ExxonMobil scheduled to begin its first LNG deliveries in 2014.

Woodside Petroleum began its first production of LNG in April from the Pluto LNG project near Karratha in Western Australia. Source: Woodside Energy.

Projects scheduled to come online in Australia over the next few years are expected to put the country on par with Qatar in terms of export volumes as well, Mr Medlock said. “In Australia alone, you see a near doubling of export volumes in the next three to four years because of projects that are already under construction.”

Chevron Australia began construction of the $29 billion Wheatstone Project off the Pilbara coast of Western Australia in late 2011. The project is expected to begin LNG production in 2016 and will have two LNG trains with a combined capacity of 8.9 million tons per year. The Gorgon Project, also led by Chevron Australia on Barrow Island, is scheduled to begin production in 2014. The Gorgon Project is expected to produce 15 million tons per year.

Off the northwest coast of Australia in the Browse Basin, Shell’s floating LNG project is expected to begin production in 2017 and will produce 3.6 million tons per year.

In North America, Canada’s west coast is most likely to take the lead in LNG exports, given lower prices and the location, Mr Gwozd explained. “The price of natural gas in Canada is cheaper; for example, today Henry Hub is about $3 to $3.50/Mcf, while Western Canada’s price is under $3.00/Mcf,” he said. “That means that the Canadian natural gas feed stock is cheaper to send overseas and thus a higher profitability.”

Distance is another factor: The projects on the west coast of Canada are closer than the US projects in the Gulf of Mexico.

Canada consumes about half as much natural gas it produces, Mr Gwozd said, which means opportunities to sell the other half to markets like Asia, where natural gas prices range between $13 to $15. Companies such as Apache, EOG, Encana, Shell and BG are establishing an LNG export presence in Canada. Mr Gwozd likened the activity to a square dance, where in Western Canada, joint ventures are attracting some Asian players, such as Kogas, Mitsubishi, Petronas and Intex.

“The square dance partners will be learning the Canadian way of doing business and will try to get involved in this square dance process and bring large sums of money to make these projects go ahead,” he explained. “Because there are so many more players looking at Canada as a whole, it also reinforces the economics that Canada is the place you want to be.”

In addition to 11 LNG terminals in North America, including the Cheniere facility that is being retrofitted to export LNG in Louisiana, there are 17 proposed and identified potential sites for LNG facilities, of which 14 would be for exporting LNG. Source: US Department of Energy.

Ironically, while the US is home to massive natural gas production relative many other countries, only one LNG project is currently licensed and under development. Cheniere Energy Partners received authorization from the US Federal Energy Regulatory Commission in April to install liquefaction services at the Sabine Pass LNG receiving terminal in Cameron Parish, La., which will essentially transform it into a bi-directional facility capable of liquefying and exporting natural gas in addition to importing and regasifying LNG.

Although some analysts are skeptical of when operations will come online, Cheniere Energy has said it aims to commence operations in 2015. The planned export total is 2 Bcf/day.

There are several applications for licenses to export LNG – ranging from the Dominion-led Cove Point project in Maryland to Jordan Cove in Oregon – totaling more than 17 Bcf/day, Mr Medlock said.

The development of an LNG export market in the US is not without challenges from political and environmental opposition, infrastructure, and commercial uncertainties. “There are a number of plans and permits that have been applied for, but it’s expected that there probably won’t be any approved for a couple of years,” Mr Wicklund explained. “When Cheniere was trying to get their LNG facility permitted, the environmentalists and others fought it, saying, ‘Instead of shipping our precious natural gas overseas, we should be using it here.’”

Infrastructure is also lacking. The existing terminals were constructed to import LNG, not export. “If infrastructure existed, we’d be exporting as much as we could because the prices in the US relative to the price in Asia reflect differentials in the $12 to $14 range. That’s more than enough to pay for a trade,” Mr Medlock noted.

Although the current price differential between the US and other markets is in favor of exports, the question is whether the price will remain sufficient to support trade. The costs of liquefying, shipping and regasifying takes a toll on the potential net earnings, and competition could also reduce prices outside the US. “Ultimately, how does contract structure change once you increase liquidity, which will ultimately happen the more players there are in the market,” Mr Medlock stated. “All that is commercial in nature.”

The potential demand for natural gas for the transportation sector in North America is gaining momentum. “In the near term, the growth won’t be spectacular, but by 2020 in the fleet sector where we feel the near-term prospects are the best, you would have fairly significant demand,” Nina Fahy, associate director, PIRA Energy Group, explained.

Based on PIRA Energy Group’s high case, by 2020, the fleet usage, which generally includes vehicles that are owned by the government or corporations, is estimated to reach 1.5 Bcf/day. By 2030, that usage is forecast to reach 4 Bcf/day. US natural gas consumption will average 69.8 Bcf/day in 2012, an increase of 3.2 Bcf/day from 2011, according to the US Energy Information Administration.

Developing one side of the equation while trying to develop the other side is a conundrum. “You’re trying to create a market for trucks that for the most part are not already built and also create a fueling infrastructure, which those trucks can then get gas from,” Ms Fahy explained. “It becomes a challenge of how you can substantially affect both sides of that equation and have it move in tandem because it really is very interdependent to have both the trucks and the stations built.”

Progress is being made, largely because of private initiatives that target both fueling infrastructure and original equipment manufacturers. LNG truck engine options are limited; however, Cummins Westport is scheduled to release an 11.9-liter LNG engine in 2013 to fill a niche. “At present, there are really only lighter engine options or heavier engine options; this will satisfy a middle ground,” Ms Fahy said.

Her outlook for progress in the NGV market in 2013 is promising, as she expects to see more LNG fueling infrastructure be built for Class-8 vehicles – trucks weighing above 33,000 lbs (14,969 kg), including tractor trailer trucks – and for public transit buses and refuse trucks. Further, she expects that each of the big three US auto manufacturers will have an NGV on the market in 2013.