August 1999 Supplement  Feature Article

SubSea MudLift Drilling JIP: Achieving dual-gradient technology

Technology development is underway by a dedicated industry group to create a workable solution to a deepwater drilling roadblocks

K. L. Smith, A. D. Gault, D. E. Witt, F. P. Botros Conoco; C. Peterman, M. Tangedahl, Hydril; C. E. Weddle, Cherokee Engineering; and H. C. Juvkam-Wold, J. J. Schubert, Texas A&M University

n early 1996, a joint industry project was started which sought to deliver dual-gradient drilling technology for use in high-pressure, low-fracture-gradient, ultra-deepwater environments. This technology is "enabling" — that is, without it, industry simply will not develop the reserves found in these environments. The work continues today as a cooperative effort between four deepwater operators, four deepwater drilling contractors and Hydril, the Project Designer. And this SubSea MudLift Drilling (SMD) JIP is on track to deliver this technology to industry in 2002.

Described in this article are: 1) definition, needs and benefits of Dual Gradient Drilling (DGD) Technology; 2) challenges of dual-gradient drilling and system / components the SubSea MudLift Drilling JIP have developed so far to meet them; 3) a review of drilling and well-control procedures with the new "unbalanced U-tube" configuration; and 4) JIP progress through Phases I and II, and objectives of Phases III and IV. The conclusion summarizes benefits / advantages of industry participation.

Dual Gradient Technology Need / Definition

In young, rapid depositional basins such as the Gulf of Mexico and parts of West Africa, pore pressures are quite high, and fracture resistance pressures are quite low. This very thin margin between the two drives us to set many strings of casing in upper hole sections, as well as deeper pressure transition zones. Consequently, industry has found that in ultra-deepwater, perhaps 8,000 ft or so, many deeper geological objectives are not even reachable, Fig. 1.

The ultra-deep water has been found to have a host of other drilling problems — shallow-water flows, massive lost circulation zones and well control incidents. However, due to the lack of contingency casings available, industry has lost one of its most effective tools for battling these problems. So, many ultra-deepwater wells are simply lost due to severe mechanical drilling problems. The result is that an ultra-deepwater GOM well can easily cost $30 to 50 million, or more, and there is still no guarantee that its geological objectives will be met.

Further, exploration is only the beginning of the problem. Any well with reasonably deep geological objectives which is drilled in ultra-deep water is likely TD’d in a 6 to 6.75-in. hole. This hole size simply does not allow for the high-rate completions, horizontals or multi-laterals necessary to economically justify development of any but the absolute best of the ultra-deepwater reservoirs, Fig. 2.

It is, therefore, quite likely that most discoveries made in 6,000-ft water, or greater, simply will never be developed using today’s drilling / completion technology. Yet industry has already spent well over $10 billion building and upgrading rigs, and acquiring / evaluating leases, all in hopes of exploiting this frontier area. A change is needed before a significant return is realized on this investment.

What is Dual Gradient Drilling? The very thin margin between fracture and pore pressure gradients is the root of all of the problems that eventually lead to the ultra-deepwater challenges mentioned above.

Today, industry uses a "single gradient drilling (SGD) technology" to control these pressures. With an SGD system, bottom hole pressure (BHP) is controlled by a mud column extending from the bottom of the well to the rig. DGD technology accomplishes the same BHP through a combination of mud from the bottom of the well to the mudline, and only seawater from the mudline back to the rig, Fig. 3.

Some of the immediate realizations with DG systems are that mud weights actually used will be higher than with a single gradient system. In addition, the well is dead with only seawater above the BOP stack, i.e., the riser margin is reintroduced to operations.

Benefits of Dual Gradient Technology. In a single gradient system, pore, fracture and mud pressure gradients are referenced to the rig. In dual gradient drilling, all gradients are referenced to the mudline. In doing so, the margins between fracture gradient and pore pressure become significantly greater.

The primary benefit from a well design standpoint is that several strings of casing are no longer needed. In fact, in ultra-deepwater, as many as four strings of casing can be removed from the well design, Fig. 4. A second benefit is that the wider margin between fracture gradient and pore pressure will lead to fewer well kicks and lost circulation problems. Well trouble time will be significantly reduced.

These benefits can lead to ultra-deepwater well savings of $5 to $15 million per well. More important, this technology "enables" industry to reach its geological objectives in virtually any water depth, and reach them in a 12-1/4-in. hole size. This hole size will allow the more exotic completions like horizontal and multi-lateral wells, and 7-in. tubing strings to the mudline. Industry will then finally realize the production potential from these high-performance reservoirs being targeted in deep water, Fig. 5.

Dual gradient technology basically eliminates the mud from the drilling riser. This can reduce riser tensioning requirements by up to 800 kips, significantly extending the water depth capabilities of smaller rigs, or increasing the rig’s ability to cope with higher current loads in a shallower-water environment.

Cheaper wells, safer operations, ability to reach geological objectives and achieve the high productivity needed in deep water — all are available with the existing rig fleet and dual gradient. It is easy to understand why DGD technology will become the method of choice for drilling in ultra-deep water.

JIP Challenge / Response

The wellbore is exposed to a pressure above the mudline of only seawater. Yet the reality is that the mud is being returned to the rig. Any dual gradient technology must overcome the mechanical obstacles associated with returning the mud and any entrained cuttings back to the rig without exposing the wellbore to the pressure of a column of mud above the mudline.

To meet this technical challenge, the SubSea MudLift Drilling (SMD) JIP is developing a dual-gradient system which enables the operator to drill extended reach wells with multi-lateral extensions, and end up with a 9-5/8-in. casing at TD in 10,000-ft water and beyond. The basis of design which drives the volume and pressure capabilities of the system are summarized here:

There are several possible configurations of a MudLift system. The primary one being studied in the JIP is run with the existing BOP stack and Lower Marine Riser Package (LMRP), utilizing the existing 21-in. marine riser. Since the riser is no longer used as a primary well control barrier, it is filled with seawater and now functions primarily as a support structure for the riser auxiliary lines, and as a guide from the rig into the wellbore. The mud return lines are the current auxiliary lines on that riser. All power and control umbilicals are attached to the riser, Fig. 6.

Subsea Mudlift Drilling System

SMD combines conventional and new, fit-for-purpose drilling equipment. To get a feel for the layout, take a trip — from the "mud’s-eye-view" — through the system. The journey begins at the rig’s existing mud pumps, which move the mud from the pits, up the standpipe and into the drill pipe, as always. However, these pumps will also run at significantly reduced pressures, as will be explained.

Drill String Valve. The mud’s trip down the drill pipe and into the well is routine, except for its flow through the Drill String Valve (DSV). This is the first unique piece of technology being developed. One of the early realizations with DGD was that when mud was lifted from the mudline back to the rig from the annulus, the mud in the drill pipe formed a tremendous U-tube effect — up to 5,000 psi, depending on mud weight and water depth. This head of mud provides effective hydraulic horsepower to help the mud pumps push the mud through the drillstring, BHA and bit — hence the low pressures from surface mud pumps.

However, when circulation stopped, for example, when making a connection or checking for a well flow, the U-tube imbalance would equalize at rates of up to 15 bbl/min for 15 to 20 min. This was not acceptable from a rig crew perspective, so a drill string valve was designed.

The DSV is essentially a pressure-balanced drill pipe float with a very large spring, Fig. 7. It will be run at or near the bit, and is adjustable on the rig for opening pressure. In tests thus far, the DSV has opening pressure repeatability within a few psi.

The mud continues its trip through the DSV, exits the bit and begins the trip back up the wellbore annulus. Everything remains conventional until the mud reaches the mudline, where it would normally enter the base of the riser. At this point, return flow is diverted from the wellbore annulus into the SubSea MudLift Module (SMM).

SubSea MudLift Module. The SMM consists of two main components, a SubSea Rotating Diverter (SRD) and a SubSea MudLift Pump (SMLP) located at the mudline.

The SRD, Fig. 8, isolates the fluid in the riser from the wellbore and diverts return drilling fluid from the riser base to the MLP suction. It contains a BHA-retrievable rotating seal rated for 500 psi in both directions, and is sized for 6-5/8, 5-1/2 and 5-in. drill pipe. One of the big challenges of the project is keeping solids too large to pump through the MudLift system out of the pump suction. The solids-sizing process begins inside the SRD.

The MLP, Fig. 9, is isolated by suction and discharge mud valves which keep hydrostatic pressure of mud in the return lines from being transmitted back to the wellbore. The MLP, which acts as a check valve, makes dual fluid gradient possible.

There are actually two pumping systems within the SMLP. The heart of the fluid end is two banks of three, 80-gal positive displacement diaphragm pumps. These are driven by four, 1,000-hp subsea electric motors powering eight hydraulic variable displacement pumps. All of these components are pressure balanced to seawater hydrostatic pressure.

An extensive selection process was performed before selecting the diaphragm pumps. However, these pumps are preferred due to their mechanical efficiency, and because there are no dynamic seals; reliability is key to success of the pump. This system adheres to the project’s overall strategy of utilizing existing technology where possible, i.e., all of these components have been proven in other applications.

The MudLift pump will ordinarily be run in an automatic mode. Its rate will be determined by its response to pressure conditions it senses in the well. This means that the driller will only need to operate the surface mud pumps, as is done today. The SMLP will react automatically, starting and stopping to match the surface pump.

Mud return to surface. The MudLift pump then pumps mud from the wellhead up the riser choke and kill lines. This pump isolates the wellbore annulus from the weight of the fluid in the riser choke and kill lines, and ensures that the well is only exposed to seawater hydrostatic pressure above the mudline. The MLP, which acts as a check valve, makes the dual fluid gradient possible.

The MLP discharges into the choke and kill lines and returns the mud back to the rig. Upon reaching surface through the riser auxiliary lines, the mud flows across the shale shakers and through the mud processing equipment, ready for another cycle into the wellbore. A rendering of a full MudLift system is shown in Fig. 10. However, many configurations are possible, and will generally be driven by rig-specific integration issues. Photographs of the diaphragm pump, mud valve and hydraulic power portion of the test flow loop are shown in Fig. 11 and Fig.12.

Drilling / Well Control Procedures

Operationally, the system becomes a little more complicated. There is a re-education necessary, but it is entirely manageable.

As alluded to earlier, a conventional drilling circulating system functions as a balanced U-tube. A dual gradient system is unbalanced. This unbalanced U-tube situation significantly affects most drilling and well control operations. Successful SubSea MudLift Drilling depends on effective management of the U-tube.

Perhaps it is easiest to understand some of the thought process changes with a few examples.

• The DSV keeps normal circulating procedures similar as today. However, the valve is absent when running casing. Cementing procedures had to accommodate this.
• The DSV makes operations seem familiar to personnel, however, it is not critical to well control — or any other operation — and the well can be controlled without it.
• Tripping out of the hole requires two trip tanks — one for mud below the mudline and one for seawater in the riser.
• Flow-checks can be done identically. Bumping the DSV open to observe drill pipe pressure is the same as with checking flow with a float in the drillstring.
• Kicks can be circulated out at essentially any flowrate. There is no limit based on ability to weight-up mud.
• BHP can be varied by either adding barite, or raising the mud / seawater interface in the riser. This feature can be used to remove Equivalent Circulating Density (ECD) while drilling.

An advantage of MudLift drilling is that all kick detection and well kill operations are not only possible but, in most cases, enhanced. An added safety bonus is that a true riser margin is always in place, since mud weight in the wellbore is always high enough to overbalance wellbore pore pressure, with seawater gradient above the mudline.

Experience with new people into the project has shown that it takes a few months before an experienced individual is able to understand the principles well enough to contribute to development of the procedures. This experience can be extrapolated; operators and contractors who simply are exposed to the technology without the benefit of full immersion ahead of time will spend a significant amount of time (and money) learning how to effectively utilize the technology in their well plans and operations.

JIP Progress

Early in the project, it became apparent that dual-gradient drilling technology would revolutionize the way industry plans and works in ultra-deep water. Totally new drilling equipment, rig integration of the equipment, well design, drilling operations, well control — all are dramatically different from what is done today. The SMD JIP created and is implementing a work program which addresses all of these issues. The overall schedule is shown in Fig. 13.

Phase I. The SubSea MudLift Drilling JIP was created to investigate ways of managing effects of hydrostatic pressure at the wellhead. Twenty-two companies participated in the first phase. Drilling contractors and operators from Europe, North America and South America all realized the importance.

In this first phase, called Conceptual Engineering, more than $1 million was invested in technical / operational feasibility studies. The group agreed on the configuration of equipment needed, and determined that both routine drilling operations and well control were feasible.

It was also agreed that re-education of industry personnel would be the most significant challenge. For drilling engineering and operations personnel, dual-gradient drilling requires a complete mindset change.

Phase II. This phase, developing the critical components, began in April 1998, at a cost of more than $12.6 million. Nine participants — four operators, four contractors and one manufacturer — are involved.

The group is currently completing Phase II, or Preliminary Engineering. It is building and testing all critical equipment components in a test flow loop. It is concentrating on the return line concept integrated with the existing marine riser, but also progressing the design of integrating MudLift with a standalone remote return line riser and a self-supporting riser.

Equal in importance to equipment development is the significant effort being expended to develop and HAZOP operational and well control procedures. The well-control simulator is advanced, and training schools for SubSea MudLift Drilling have begun. Training industry personnel to fully understand the technology, and how to apply it safely and efficiently, is a significant challenge.

Phase III. Focusing on System Design and Preliminary Field Testing, this phase will run during the year 2000 and early 2001, and cost between $15 and $16 million.

Field testing will be conducted in a shallow-water environment to test operation of MudLift System components in a drilling environment, and effectiveness of the newly-designed procedures. The shallow-water trials will be vigorous, in preparation for the more-expensive "deepwater lab." Operational and well control procedures will be completed, and training schools will be developed. The necessary regulatory approvals will be secured.

Finally, tested and proven components will be designed into an integrated system for the selected deepwater test rig.

Phase IV. This will lead to commerciality of the SubSea MudLift system. The full system will be built in 2001, and then be tested in early 2002. This final phase is expected to cost about $12 to $18 million, as at completion, the test operator will have the option of buying the test system from the Project.

The JIP’s goal is to deliver a commercially available system — and the entire training and support infrastructure to safely and efficiently use it — to the participants in mid-2002.

Why Participate?

The need for the technology is obvious. Without it, the ultra-deepwater environment will die as an exploration and production opportunity and, with it, the market for the rigs that have been built to service that market.

However, the cost of developing this technology is huge, and it is easy to take a stance of simply waiting for the technology to be delivered to the industry. Yet, there are several advantages for JIP participants:

1. As a participant, you will have full access to the SubSea MudLift System before any will be sold to non-participants companies.
2. As an operator, early access provides significant savings in well costs and added production potential.
3. As a drilling contractor, this will firmly establish your reputation as an ultra-deepwater player, one who is leading the industry’s demands of the evolving market.
4. Whether an operator or a drilling contractor, your advantage is in being able to fully understand the technology, and how to apply it safely and efficiently to your deepwater business.
5. Actively contributing to the technology development — via the JIP — will enable you to integrate this new technology into your business with a minimum learning curve, avoiding, potentially , several $ million in added learning costs.
6. There is a licensing system designed to reimburse participants for contributions to developing the technology.

The SubSea MudLift Drilling JIP is the beginning of an evolution of new technology that will expand into other applications, achieving even greater benefits / savings. Dual-gradient drilling is reshaping the deepwater drilling’s future.

Acknowledgment

It would not be appropriate to close this article without recognizing the team assembled by Hydril and the other JIP participants. This team consists of world-class engineers in electronics, power transmission, control systems and software design, drilling hardware, materials science and system integration. We want to extend our sincere appreciation to the team for their significant efforts on this once in a lifetime project and to our respective companies for their continuing support. We especially acknowledge Karen Moody, Conoco, who compiled the efforts of the people in the JIP, and created a large portion of this article. Finally, and most important, this technology would not be delivered without the continued support of the project participants. These companies are cooperatively and collaboratively leading the industry in ultra-deepwater exploitation. They are BP Amoco, Chevron Petroleum Technology Co., Conoco Inc., Diamond Offshore Drilling, Inc., Global Marine Drilling Co., Hydril Co., RB Falcon Drilling (International & Deepwater) Inc., Schlumberger (Sedco-Forex Div.), and Texaco Group Inc.

The authors

Kenneth L. Smith, PE, Project Manager for the SubSea MudLift Drilling (SMD) JIP, in the Deepwater Technology Development Group of Conoco, Inc., received his BS in PE from Texas A&M in 1978. He has since worked in various onshore / offshore D&P capacities around the world. He has been involved in this JIP project since 1996.

Allen D. Gault, PE, currently the technical lead for Drilling Procedures in the SMD JIP, received his BS in ME in 1975 from the University of Houston and an MS in CE in 1990 from Texas A&M. He has worked for 201 years in technology development and transfer and is active with the DEA, AADE and SPE. Mr. Gault and Charles Peterman initiated Phase I of the SMD JIP which established the need for the technology and was the basis for the JIP to move forward.

Dana E. Witt, a Senior Staff Drilling Engineer in Conoco’s EPT Drilling Group, received a BS in PE technology from Oklahoma State University in 1980, and has since worked in various drilling roles around the world. He is currently assigned to the SMD JIP, developing drilling procedures.

Fikry R. Botros, received his PhD from Columbia University in 1982, and joined Conoco in 1984. He has over 15 year’s engineering experience with offshore platforms, and has held various project leadership positions in major offshore projects. He is involved in several deepwater technology development projects with riser / tether design, as well as the riser analysis performed on the SMD JIP.

Charles P. Peterman, Director of Research for The Hydril Co., received his BS degree in EE from the University of Kansas. He has 42 year’s experience in D&P operations, having made numerous contributions to offshore equipment development in controls, reentry, BOP stacks, risers, and more. He spent the last 12 years managing several company business units, and has been a key figure in the SMD JIP since its inception in 1996.

Michael J. Tangedahl, PE, Hydril Co.’s Program Manager for the SMD JIP, holds a BS engineering degree from the University of Houston. Formerly vice president of engineering / operations for Inter-Tech Drilling Solutions, he has 15 year’s experience with oil tool / drilling service companies as VP of marketing / engineering / manufacturing, plus 25 years of engineering. He is an active member of SPE, IADC, Society for Manufacturing Engineers and the American Society of Metals.

Curtis E. Weddle, III, PE, Team Leader for Well Control Procedures for the SMD JIP and a principal of Cherokee Offshore Engineering, is a 1978 graduate of Oklahoma State University with a BS in CE. Before forming Cherokee, he worked for Exxon and BP on a variety of D&P and technology projects worldwide. Mr. Weddle is active with IADC and SPE. He has been involved with the SMD project since 1997.

Hans C. Juvkam-Wold, the John Edgar Holt Chair Professor of Petroleum Engineering at Texas A&M, holds SB, SM and ScD degrees in ME from M.I.T. His principal research areas are well control and deepwater drilling. He has over 20 year’s of varied oilfield experience, and he has been involved in this JIP since its inception.

Jerome J. Schubert, PE, a Lecturer in Petroleum Engineering at Texas A&M, teaching drilling engineering and well control, received his BS (1978), MS (1995) and PhD (1999) in PE from Texas A&M. He has worked as a drilling engineer for Pennzoil and Enron Oil & Gas, and as a well control trainer. He has been on the Well Control Team for SMD since 1998.

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