Outsmarting Mother Nature

[flv flashvars=”file=https://drillingcontractor.org/wp-content/uploads/2012/03/3__Instant_Pressure_Regulation.flv&&image=https://drillingcontractor.org/wp-content/uploads/2012/03/poster-instant-oceanriser.png”]https://drillingcontractor.org/wp-content/uploads/2012/03/3__Instant_Pressure_Regulation.flv[/flv] [flv flashvars=”file=https://drillingcontractor.org/wp-content/uploads/2012/03/7_Always_Riser__Margin.flv&&image=https://drillingcontractor.org/wp-content/uploads/2012/03/poster-always-oceanriser.png”]https://drillingcontractor.org/wp-content/uploads/2012/03/7_Always_Riser__Margin.flv[/flv]

Dual-gradient drilling technologies enhance pressure control from seabed, help navigate through precarious zones

By Katie Mazerov, contributing editor

The oil and gas industry has conquered many a force of nature in its history, but management of wellbore pressures remains among the trickiest challenges still being confronted on a daily basis in drilling operations around the world. From increasingly depleted land and offshore fields to the growing number of high-pressure, high-temperature (HPHT) wells to the ultra-deepwater frontier, formation and fracturing pressures can still make or break a well.

Over the years, managed pressure drilling (MPD) – the technique of maintaining bottomhole pressure by controlling or adjusting the density of the drilling fluid in a single column of mud from the rig to the bottom of the well – has allowed the industry to push through pressure barriers. But as wells have become increasingly complex, advances have been necessary to stay within the narrowing window between fracture and pore pressures that can present well control problems. Additional casing strings may be required, slowing down the drilling process and causing nonproductive time (NPT).

Nowhere are these challenges more evident than on ultra-deepwater fields, where the combined pressures of the water and sediment often create difficult scenarios. Dual-gradient technologies are being developed to manage pressure from the seabed to provide better wellbore stability and lower costs by reducing the number of casing strings required.

Although not currently commercially available, several dual-gradient drilling (DGD) technologies are in test or pilot phase, with Chevron planning to deploy a subsea mudlift DGD system in the ultra-deep Wilcox Formation in Gulf of Mexico (GOM) late this year.

“The GOM is the poster child for applying this technology,” said Ken Smith, dual-gradient drilling project implementation manager for Chevron North America, which is currently drilling wells from 20,000 ft to beyond 30,000 ft in the region. Although a single column of mud is typically used in conventional offshore or land drilling, the dual-gradient approach can be advantageous for

deepwater conditions.

“The pressure at any point in the well is largely a function of the weight of all of the seawater and sediments above it,” Mr Smith explained.

“In ultra-deepwater, the seawater tends to dominate the pressures that are deeper in the wellbore. Today, we currently use a single-density mud to manage these pressures. That means we are using a drilling fluid that is denser than the seawater and less dense than the sediments, so we’re not really aligned with the natural pressure profile found in nature.

“In dual-gradient drilling,” he continued, “we manage two fluids: a seawater-density fluid in the drilling riser and a denser-than-conventional drilling fluid below the

mudline, more closely paralleling the pressure profiles found in nature.”

Chevron’s dual-gradient technology was developed and tested 10 years ago in a joint industry project (JIP) with GE Oil & Gas and proven in the world’s first DGD well in 2001 in the GOM. After a seven-year hiatus, work on the technology was resurrected in 2008 in the face of greater and greater ultra-deepwater drilling challenges.

Over the years, the original JIP and Chevron have invested 25 man-years of operations and well-control procedure development and training to ensure safety and efficiency, according to Mr Smith.

GE spent more than three years designing and manufacturing the SubSea MudLift Pump, which senior project manager Ahmet Duman described as the “heart of the entire system.” The 30-ft-high pump, the size of a lower blowout preventer (BOP) stack, is powered by seawater and will lift mud to the surface from the seabed floor. It is rated to 10,000 ft and can pump up to 1,800 gal/min.

“Safety is our No. 1 focus, and we will only deploy this if we’re absolutely comfortable with it,” Mr Smith said. “We are very confident in the technology and the mechanical abilities of the hardware, but this is still a challenging technology to deploy, completely different than anything we do in conventional drilling. DGD isn’t the only way to drill, but we think it has the potential to be a better way to drill.”

Ocean Riser Systems (ORS), an Oslo-based company that provides technology and pressure management services to the subsea and deepwater drilling and well intervention market, will deploy its dual-gradient Low Riser Return System (LRRS) within a year, for a pilot subsea project on the Norwegian continental shelf.

“We are seeing this type of technology increasingly being requested by both the regulators and by the industry, with at least five oil companies planning similar pilot programs,” said Dr Kristin Falk, manager of MPD control systems. ORS is confident the project, which has been in development for 3 ½ years, will allow the operator to continue drilling new wells in the field without encountering severe pressure-related problems, such as lost circulation, in the reservoir sections. The technology will also help achieve higher-quality cement jobs for zonal isolation within a reservoir with changing pressure regimes.

“In depleted reservoirs, we see different pressure zones, situations where we are drilling with relatively high pressure, and then moving into a low-pressure zone,” Dr Falk said. “But if the reservoir pressure becomes too low or falls below that of a liquid mud gradient, it becomes a challenge to drill new well sections within the reservoir.” The company has looked at a number of subsea

fields in Norway, the UK and West Africa with this type of problem.

“With the LRRS system, we can easily and quickly change between different pressure zones. In this specific field, we can compensate for the depletion effects while drilling with a conventional mud weight (no need for foam or gasses to be added to the drilling fluids),” she continued. “This makes it possible to drill longer well sections, improve the cement job, have higher margins to fracture pressure and pore pressures and drill these wells with a riser margin in place.”

The LRRS technology is based on the principle of a partially filled riser and is an open MPD system tailored for subsea drilling from floating vessels. By adjusting the level of mud in the riser, the bottomhole pressure (BHP) can be changed in minutes rather than hours. This is achieved by returning mud and cuttings to surface through a separate return line from a subsea outlet on the riser using a submerged mud pump. The upper section of the riser is ventilated to atmospheric pressure.

The riser is fitted with pressure sensors that determine the mud level in the riser. A dedicated level-control system maintains the desired mud level and monitors the operations.

The partially filled riser allows the use of heavier mud weights than what could have been used with conventional drilling. The results are improved margins, as well as the potential for improved casing programs and cementing operations. By providing both drilling and riser margins to a greater water depth than with conventional drilling, the LRRS system enables faster and safer deepwater drilling.

“We have conducted a lot of analysis on this technology and believe it will be a game-changer for both deepwater fields and in shallower water environments, including Norway, GOM, Brazil and West Africa, where many subsea wells are being depleted,” Dr Falk said.

“With this system, we can drill farther, faster and safer and thus, deliver more success for operators in getting where they need to be to produce and recover more hydrocarbons.”

Since 2003, Statoil has used MPD and underbalanced drilling (UBD) on several fields with success, the most notable being the Gullfaks and Kvitebjørn fields. However, the focus is now turning toward dual-gradient solutions that may help drill difficult deepwater wells more efficiently.

Statoil has used automatic MPD technology for several years on the Kvitebjørn field, which has a number of HPHT wells with temperatures up to 311°F (155°C) and pressure around 800 bar (more than 11,600 psi). The wells are roughly 4,000 meters true vertical depth, with a corresponding length of about 6,500 meters in measured depth.

“The MPD technique is giving us more control of the wellbore pressure and provides a solution for drilling sections where the drilling window is narrow due to depleted zones and zones where initial pressure is present in the same hole section,” said Dag Ove Molde, drilling technology specialist for Statoil.

The technology involves combining a reduced-weight mud and surface-controlled backpressure to control the downhole pressures. An automatic choke was used with an advanced hydraulic simulator for the first time in 2007 to address variations in the BHP caused by temperature changes and other conditions in the HPHT environment.

On the Gullfaks field in the northern North Sea, UBD and MPD were implemented back in 2003. In 2009, Statoil and a supplier developed an automatic MPD system to maintain the BHP within a narrow pressure window. “In the Gullfaks field, we are putting a lot of effort into developing new technology, both within Statoil and externally, to meet the challenging drilling conditions in the best possible manner,” Mr Molde said.

This year, Statoil will begin testing a “dual gradient light” system for a shallow-water field (less than 500 meters) off the coast of Norway. “Dual gradient is a concept Statoil believes in, especially for deepwater challenges,” he added. As a first step in the development, Statoil is planning two pilot projects on the Troll Field.

“Our intention is to reduce the hydrostatic pressure in the well while drilling the depleted formation, by reducing the fluid in the riser,” he described.

DGD-ready rig set for GOM program

The SubSea MudLift system that is the centerpiece of Chevron’s dual-gradient drilling (DGD) technology will be deployed from Pacific Drilling’s Pacific Santa Ana, the world’s first DGD-ready rig. The minimum five-year deepwater Gulf of Mexico program is expected to begin late this year.

The rig is capable of drilling to 40,000 ft in water depths up to 12,000 ft. It has a modified drilling riser that includes a seawater power fluid line and a mud return line, along with six mud pumps. A subsea rotating device separates mud from the riser fluid. The rig design was significantly modified to provide for the separation of the fluid systems and allow the mudlift pump to be moved from one side to the other.

“One of the features that differentiates the Santa Ana from other rigs is the fluid-management system, which is extremely advanced and enhanced over what is normally on a vessel of this size and capacity,” said rig manager Ricky Chambers. “This is based on the fact that we actually have to handle three fluids at the same time – the seawater fluid, the mud and the riser fluid. What we have inside the riser from the vessel down to the top of the rotating head is different from the seawater and what is in the wellbore.”

The marine riser was designed to accommodate the additional lines for the seawater power fluid and for the returns to come up through the external line on the riser. The riser has extra 6-in. pipes for handling the dual-gradient fluids. “The power distribution system also was modified because we have more equipment we have to supply power to than on a conventional rig,” Mr Chambers said.

Another feature centers on the ability to handle and stack the mudlift pump onto the lower marine riser package (LMRP) inside the moonpool. “We had to engineer some modifications to enhance our ability to handle load in the moon pool,” said Kevin Wink, US operations manager for Pacific Drilling. “In the setback area and test location, we are providing an additional guidance system for moving the mudlift pump from the test location to the well center.”

Addressing the narrowing window between pore and fracture pressures is one of the overarching objectives of MPD, said Sara Shayegi, senior well engineer for Shell International. The narrow pressure window translates to increased cost due to more kick/loss incidents, NPT and drilling problems that, in some cases, can result in not achieving targets. As production goes on and reservoirs get more depleted, that margin is only getting narrower.

“Shell uses MPD technologies on more than 75% of the wells drilled and has developed technologies and trialed systems to optimize the economics of drilling,” Ms Shayegi said.

“In some areas, a point has been reached where the MPD tools are adequate to solve the majority of issues related to the narrower pressure envelope. But in other cases, technologies are going to have to be developed or refined to allow the industry to control the pressure profile even more precisely over the different phases of well construction.”

The solution can come from improvement in several areas, including real-time integration of data and information into “intelligent systems” with different degrees of control depending on what is needed in a region. Other solutions may encompass enhancement of predictive and control algorithms, further automation, improvements/development in ancillary equipment, and optimization of procedures.

“If the pressure gap is fairly wide, not much automation is needed, so manually operated chokes can be used,” Ms Shayegi said. “But as the window narrows further, better control is needed with advanced systems that have some degree of automation.

For example, to maintain a stable BHP, a smoother transition between drilling and connections can be achieved by automated control to coordinate the choke, backpressure pump or rig pump diverter, compared to manual control.” Alternatively, continuous-circulation valves, in conjunction with an MPD system, are being tested to achieve this same objective. Addition of automation to other components and processes will likely increase to exercise even more precise control during other drilling operations.

Integration of data from various service providers with the MPD data also becomes increasingly necessary for better event detection. “Currently, different event-detection systems are available, but we don’t have corollary responses,” Ms Shayegi said. “Eventually, as automated systems develop further, we can move from system alerts and recommending a response to an incident, to possible first-degree response.”

“With MPD, it is possible to detect events earlier since you have additional indicators compared to conventional drilling,” she added. One example would be the automated choke response, which is one of the earliest indicators of a kick or loss for an MPD system using a surface choke. This inherent characteristic allows for gaining a better understanding of the environment while drilling, which is useful for future development.

“Sometimes the pore and fracture pressures are not precisely known in a given area, but with MPD, there is more leeway in designing muds and adjusting backpressures to where they need to be. It provides a better way to know the limits while at the same time allowing more precise pressure control,” she said.

Information on pressures also aids in well design for the area.  Shell has developed techniques to use the information for better understanding of the reservoir with different reservoir characterization techniques for different MPD implementations.

“If developers can optimize event-detection, automation and data integration, it will be possible to fine-tune the system to work better in the available pressure envelope,” Ms Shayegi said.

Hand in hand with that is training. “It is important to ensure operators have a strong basic understanding of conventional drilling concepts and well control, and ensure engagement of personnel as different levels of automation and control are put in place,” she added.

“Engagement means that pertinent data and information from ‘intelligent systems’ are available so that onsite engineers and rig operations personnel can make timely decisions and timely interventions. System automation means that the people need to be more skilled in understanding the overall system.”

A key well control tool used in land and offshore MPD operations is the rotating control device (RCD), which provides a seal against the drill string so that return mud goes through a choke system.

“In cases where high surface pressures are not needed, a lower-pressure-rated RCD can be used,” Ms Shayegi explained. “But in some fields, higher surface pressures will be needed, such as HPHT applications that require higher pressures be applied at the surface, and the elements within the RCD will need to be able to withstand higher temperatures in some cases.”

Although MPD technologies have concentrated on drilling, looking forward indicates that the entire well construction process, from drilling through completion, needs to be addressed so that it is possible to control the pressures within the narrow margin available from start to finish, Ms Shayegi believes.  MPD technologies are starting to be used for cementing; next the industry will need to look at improvements for completions.

“The industry is going to have to look at the design of equipment for running liners and other equipment to the bottom of the wellbore where narrow pressure windows are present,” she said. “The tools used, the clearances, setting methodologies, pumping for actuation or conversion of cementing float equipment, etc, need to be looked at and the impact on the pressures determined and alternative practices evaluated, where this has a detrimental impact.”