Underbalanced Drilling

A drilling contractor’s view of underbalanced drilling

A frank discussion of the basic problem of different operational perspectives by operator and contractor, with case history examples of industry’s painful learning curves, and success in Colombia

Ross D. Murphy and Paul B. Thompson, Parker Drilling Co., International

This article is not a technical discussion of underbalanced drilling (UBD). It is a discussion about the best method – from one drilling contractor’s view – to execute a safe and productive UBD project. There is no magic formula, no exotic management technique and no revolutionary equipment design that will guarantee success. This is a frank discussion about the "mindsets" that operators and drilling contractors have when approaching a UBD project. The goal is to help both parties better understand the strengths, weaknesses, needs, concerns and objectives of each other to better deliver a successful project.

The contractor’s challenges are presented; undesirable outcomes are discussed; and relevant problems from industry’s Austin Chalk UBD experiences are used as examples. A successful program in UBD drilling in Colombia, Figs. 1 and 2, shows how it can, and should, be done successfully.

Fig. 1. Parker Drilling Co. Rig 221 operating for BP-Amoco in Colombia.

Fig. 2. Underbalanced drilling equipment, by Weatherford International, interfacing with the drilling rig in Colombia.

Introduction

Underbalanced drilling techniques are evolving at a rapid rate. The technology changes as experience is gained in this "art form" for maximizing hydrocarbon production. There is such an emphasis on this technique that IADC, along with SPE and other industry groups, formed the UBD Technical Forum as a means to discuss and study this new technology. This group is tasked with setting industry standards for UBD techniques / equipment. The technology has evolved to the level of drilling H₂S wells "live," allowing H₂S to the surface, along with generating N₂ as a fire suppressant and part of the drilling fluids – industry and its techniques have truly evolved.

One key component of UBD is effective use of drilling crews and drilling contractor equipment. Stated simply, the intent and goal of drilling underbalanced is to allow the controlled flow of hydrocarbons to surface. This runs contrary to every instinct of a driller and to every training course in well control. Changing the mindset needed to successfully drill underbalanced is a great challenge. The following discussion presents the problems and solutions of involving the drilling contractor in this evolving technoogy.

Parker Drilling Co. has been involved in many UBD projects during the past 30 years. Techniques have ranged from drilling with low-weight mud or water using a gas buster, a pack-off device (often referred to as a rotating head) and a remote choke as the primary method of controlling flow to surface, to the latest rotating BOPs, high-pressure fluid separators and complex dual-remote digital chokes. The goal of each technique is: lower overall well cost and improve production safety. Results have varied from total loss of well control and subsequent blowout, to production increases never imagined. The connection between all of these techniques and those visualized for the future is drilling crews and drilling equipment.

Contractor Challenges

For the drilling contractor, there are numerous challenges to overcome. The contractor is essentially a miner, supplying equipment and people that physically bore a hole in the ground to the mineral-bearing strata. The skills needed to perform this task are:

• Strong mechanical and electrical aptitude, and knowledge of various power systems
• Ability to manage a multi-disciplinary workforce of educated and under-educated workers
• Operation of complex machinery that delivers the desired range of outputs for the customer
• Ability to work with a customer who has superior knowledge of the intended target
• Interaction with various additional contractors performing specialized tasks that require some assistance from the drilling contractor, and
• Performance of all tasks without injuring a worker, damaging equipment or polluting the environment.

The list is general, but the obvious area of concern is the drilling contractor’s lack of knowledge, or skill, in the downhole portion of the project. Operating companies, conversely, frequently have expert subsurface skills, but little knowledge of the equipment needed to deliver the wellbore in an evaluatable and productive manner. As evidence of this, a typical tender for rig services includes little information on mud systems (other than type, oil- or water-based, and weights), bottomhole assemblies, bit selection, drill-motor selection or rotary torque requirements. Predominant questions center on mast and pump pressure ratings, drawworks input horsepower, mud-tank volume, BOP ratings and other catalog-oriented specs.

The problem lies with the intended use of the equipment and ability of the contractor to translate customer needs into a machine that delivers the desired result. This is further compounded by the nature of competitive bidding for complex projects. The operating company frequently has neither time nor staff to properly review the project in detail with all of the bidding drilling contractors. In summary, the mindset is frequently, "just give us the equipment as per the specs; we see the big picture and how the various subcontractors will work together to deliver what we want."

Undesired Outcomes

The authors’ experience has been that major well-control incidents occur during completion or testing. Two recent catastrophic blowouts occurred during completion operations when the well was "safe." Investigation revealed that the men, operator and contractor, relaxed during the portion of the operation when potential problems should have been least likely; i.e., they were not fully focused on the well-control aspects, even though the wells were perforated and capable of flowing at high rates.

Most older drilling operation professionals will state that they rarely had a well-control incident when the operation was perceived to be at a dangerous point – this type of operation being defined as drilling into a known high-pressure reservoir, or snubbing, or other operations that involve reliance on equipment integrity and the skills of the people to control the well flow. When we expect the problem, we are most prepared and alert.

Drilling contractors are best trained and equipped to "dig and case the hole." They are not best trained or equipped to complete or test that hole. Completion and testing operations are usually conducted with third-party personnel skilled in this area, but unskilled in the operation of the rig’s hoisting, pumping and well-control systems. The third-party personnel focus on their area of expertise and responsibility, and the contractor personnel focus on doing tasks more associated with the machinery than with well operations.

When an incident occurs, third-party personnel are expecting drilling contractor personnel to react and work in a manner that prevents uncontrolled flow at the surface, yet these personnel are ill-equipped to understand the completion / testing operation and the implications their actions will have on the wellbore. They react as per their well-control training, but sometimes these actions are not the correct action because of the downhole tools involved, the wellhead or BOP configuration, or the movement of wellbore fluids. The end result is that problems can be made worse by the "correct" action of the contractor personnel.

Training from a different perspective. The cause of the problem described above is identified in a couple of areas, as discussed here. First, drilling contractor personnel are trained by a very specific program to react in a structured manner to combat a well-control situation. In other situations, such as stripping or spotting weighted fluids, training has typically prepared the crew for unexpected results. This type of training is mostly focused on drilling situations, not completion or well testing.

Downhole concepts such as swab and surge are well known to a driller when he is drilling or running casing, but may not be as well understood when running a packer or liner isolation assembly. Even though running a packer can cause much higher swab and surge pressures, the driller believes that, "I am in cased hole and this isn’t a problem." The issue is that training is focused on specific actions / reactions, frequently training men to behave as robots or computers.

Second, drilling personnel mentally hand off responsibility to a third party "expert" when he appears onsite to carry out a portion of an operation. For instance, when a drillstem test is run, the driller usually defers to the DST company expert on manipulating the tool to get the desired result, without fully understanding the means by which the tool operates. He may take direction from the DST-tool operator, who does not understand the rig configuration. At this point, the driller does one thing and the DST tool operator or company representative intended a different action and outcome. A problem may then become a disaster.

This example shows a well-known problem in our industry: lack of fully understanding the mechanics, engineering and physics of an overall operation can lead to a disaster. The simple solution to the above example is to follow a standard practice of job planning, and a "what if this happens" type of discussion outlining the problem, the needed action and the responsible party. Basically, it is Job Safety Analysis (JSA) or pre-job planning.

Why is this a problem with UBD? The problem is magnified when underbalanced drilling systems are contemplated. The drilling contractor is focused on delivering a machine that will perform to tender or contract specs, not on how the interface between UBD equipment and techniques will work. In our experience, about 50% of the time when UBD is being contemplated, the drilling contractor is not included in early project-planning stages because the contract has not been awarded. On other projects where the contractor is part of the UBD team, the performance of both operator and contractor is efficient and safe. This does allow the drilling contractor the opportunity to review important aspects of being able to perform to the operator’s expectations.

Austin Chalk Example Problem

Another example from recent history can better clarify the above points. The Austin Chalk formation in Texas and Louisiana was, and still is, the target of using UBD and horizontal well techniques to maximize oil production. The formation is well known as a "hit or miss" target due to the natural fracturing needed to be productive, i.e., operators drill horizontal wells to intersect natural fractures. When fractures are present, the wells can be highly productive, characterized as "high volume-low pressure."

Two reservoir conditions and preferences by operators require the wells to be drilled using UBD. First, the Chalk is a serious lost-circulation zone when natural fractures are present. Hence, the goal (finding fractures) is also a major drilling problem (lost circulation). Second, when losses occur, the well is also likely to be highly productive. Compounded by drilling the reservoir horizontally, when a lost-circulation fracture is encountered, the next fracture may be highly productive.

The contractor sees a reservoir that "drinks and blows." When losses occur, he reacts in one manner; then the well kicks, and he is forced to react in a different manner. Technically, this problem was managed (not solved) by use of rotating BOPs, open-topped production tanks, fire-suppressing foam systems, long flare lines and a variety of mud gas separators, choke manifolds and temporary production schemes.

Operating companies and third-party contractors were quick to devise methods for dry drilling (drilling without mud returns), containing the well flow up the annulus via the rotating BOP, directing produced fluids to production tanks for venting or sales of gas and oil. The driver here is that the operator could sell product while drilling as a means of increasing profitability and minimizing potential damage to the wellbore (plugging the productive fractures); i.e., the wells were produced during the drilling process.

A dangerous mix of hazards. The hazards were quickly identified, as there were numerous well and rig fires that resulted in deaths and large loss of equipment and money. The obvious hazards were:

• Volatile hydrocarbons at surface near an ignition point (drilling machinery)
• Open-top tanks (usually converted mud tanks or water tanks) containing the oil
• Dependence on a rotating BOP (that technically is not a BOP, but a high-pressure diverter with little industry evaluation or API standardization)
• Dependence on a foam-generating unit to control a fire on an open-top mud tank container burning oil. These units are mostly homemade, with no substantial industry evaluation.

To every contractor, this was a dangerous mix. Add to this list, drilling personnel who were called on to operate a rig with a base crew of five people who were expected to operate the drilling machinery, monitor well conditions and maintain the rig and BOP systems for use at any time. Further, most operators rented a portable top drive for drilling the horizontal section. Usually, the rental company supplied a person to assist with the top drive, who typically left the project as the driller gained experience with the unit.

Further understand that, in the U.S., a driller is not required to have well-control certification to operate a rig on non-federal or non-state lands onshore; i.e., the driller usually did not have any training in well-control procedures. He relied on the tool pusher to tell him what to do. For several contractors in this area, toolpushers were asked to supervise more than one rig at a time – hard to believe, but true.

In addition, as the well was drilled, the operator would have onsite many additional, third-party contractors to assist the operation – mud loggers, wellsite geologists, directional drillers, truck drivers hauling drilling mud or produced oil, roustabouts maintaining the location or moving equipment, casing crews, pipe inspection crews, foam system crews, and a host of visitors to see the operation, sell services or just watch a big gas flare. In summary, a circus was being conducted.

Market, economic pressures. To make the matter even more ripe for disaster, the bulk of the projects were being driven by U.S. independent oil operators that lacked the stringent well-control and operating standards of the well-known major oil companies. This is not criticism of the independents, as these companies drill 80% of the wells in the U.S., and are the key market driver for the U.S. industry. It is a statement that market conditions drove the process, i.e.:

• A reservoir that declines 70%/yr, hence, reserves are short-lived
• Low economic rates of return (ROR) by conventional standards
• Competition for leases and drilling commitments, and
• Shortage of skilled drilling people due to the oil bust of the 1980s.

Economic pressures on the operating companies created a "mass production" mentality that many wells had to be drilled to continually "feed" project economics. A few companies were successful and pushed the industry to adopt better operating standards, equipment designs and regulatory standards. The unsuccessful ones drove themselves and some contractors to the edge of bankruptcy as a result of the push to drill more and more wells cheaper and cheaper. In the end, these companies disappeared, leaving a legacy of problems and opportunities for companies not so driven to solve and prosper.

Drilling contractor problems. Problems facing the drilling contractor were numerous and at times unmanageable, including: untrained and inexperienced crews; economic pressure to limit the number of personnel onsite; lack of input into equipment / system designs – too many "mom and pop" companies were marketing equipment without regard to the interface between rig and equipment. And when training occurred, it ran contrary to techniques used in the field, e.g., there was no specific training on "mud cap" drilling or drilling with the well flowing live hydrocarbons.

The end results were numerous fires, blowouts, fatalities and loss of equipment. One extreme occurred in Louisiana, where regulatory authorities denied drilling permits for one operator until it could demonstrate it could drill a well without a fire or blowout. Mineral owners and landowners finally raised serious complaints due to loss of production and pollution, and new regulations were enacted.

What’s the solution? Not an easy question, as hindsight is always perfect. But several obvious lessons were learned:

1. Understand limitations of the people actually doing the work.
2. Know that training is good, but must be directed at the needed outcome.
3. Plan the process.
4. Use proven industry practices. If none exist, network to develop them.
5. Select equipment and people based on demonstrated skills and competence.
6. Be wary of market-driven practices when the market is only interested in a quick financial return.
7. Create the environment or project where people are allowed to do what they do best; i.e., do not ask drillers to be experts with third-party equipment or people. Train them first, and then involve them in the planning process.

The basic premise is simply to use the management tools we have, develop the equipment and skills we need, then, and only then, initiate the work. The end result of not doing this is that the industry learned a serious and expensive lesson when untrained people using untested equipment applied a new technique in too many situations.

One Example UBD Solution

A recent UBD project was completed in Colombia in a known, highly prolific oil field. The geologic structure was defined from previous drilling; reservoir characteristics were known from extended production testing; and drilling techniques evolved through the normal learning curve of trial, error and re-trial.

Reservoir engineers identified some causes of abnormal or high-rate production decline – skin damage, not enough reservoir exposed to the wellbore, poor or misplaced perforating programs, poorly executed well-stimulation plans and other common problems. Underbalanced drilling was offered as a possible solution.

The operator did the needed investigation of techniques currently in use, evaluated various companies providing the services, and then did a full technical review of the process, including hazard identification, equipment design studies, visits to contractor / third-party contractor facilities and study of relevant API and internal standards. When conflicts or problems were uncovered, the issues were addressed and solved. If new equipment needed to be designed or created, it was done so in a structured and documented process.

The overall goals of the operator were: 1) deliver a more economic wellbore at reduced cost; 2) do this to an international and corporate HSE standard that did not compromise safety; 3) involve contractors in the process with significant incentive to produce / provide products and people that can deliver the goal; and 4) plan, revise and execute the project on budget and on time.

These goals were communicated to the drilling contractors and other third-party contractors invited to participate in the project. The operator narrowed the selection of contractors based on availability of equipment, skilled people, performance history, HSE performance and price. But price was not the project driver. The driver was lowering total project cost on a unit or per-barrel produced basis. To a drilling contractor, the benchmark of using "dollar per barrel" is not as easily understood as "dollars per foot." But once the concept was made clear, the project mission and goal became much more apparent.

The success process, team concept. Once explained and understood, the operator chose to set up two UBD projects using different drilling contractors and some of the same third-party contractors. The decision to use two drilling contractors was a function of having both available in the area; both had world-class equipment and people. Both were asked to provide input into the training of rig personnel in UBD techniques, well-control and downhole understanding. Additionally, each was asked to review personnel currently available to see if they matched the skills needed. As project planning began, all parties met on a regular basis.

The team concept developed as a result of the people pulling together to achieve a common goal. Every team member must have the same long-term goal and be rewarded for achieving this goal. The operator was careful to select a team that had common commitments to HSE standards, and to achieving the result of delivering a wellbore, drilled underbalanced, that had the potential to produce at increased capacity.

The technology. The equipment was complex, yet simple to use. The operator selected a UBD system that required minimal change to the drilling contractor’s basic equipment. This helped manage the interface between companies. Further, it clearly defined physical areas on location where equipment responsibilities started and stopped. An example was installation of the UBD production equipment – flowlines, high- and low-pressure separators, storage tanks and flare lines. This equipment was single-sourced from a third-party contractor. This contractor mobilized, installed, operated and maintained this equipment with minimal support from the drilling contractor personnel. This yielded good and not-so-good results.

The good results were that a well-planned and structured installation process was followed. The process involved testing of tanks, lines and electronic measuring equipment to standards set during planning. Drilling contractor personnel assisted only in the physical movement of material and equipment. When installed, the areas were physically marked off with stakes and tape to be sure everyone knew their boundaries of responsibility. This minimized the potential for interference in duties and controlled the number and location of people on the wellsite.

The "not-so-good" results were that this tended to alienate people on the same team. The boundaries were intended to create clear lines of authority, but they actually prevented some learning from occurring. Most people want to learn about equipment that they have not seen. The boundaries kept this from occurring, except during times the equipment was not being used.

Training, personnel selection. Obviously, the new team required training. Conventional training included standard well-control practices. Every person with the ability to be involved in an incident was certified in well control, including national and expatriate staff. The problem arose that the standard well-control training did not cover UBD techniques. New courses were developed that explained the physical principles and how these affected actions taken by the men on the rig. The concepts of how production separators work, wells are choked while drilling (vs. choking while killing), inflow / outflow volume data and pump pressure interpretation were included. Several hazard reviews and emergency response plans were developed and tested.

The rigs used in the project had previously drilled in the area and were well known by the operator. The same applied to the personnel. At the beginning, each company involved committed to leaving the team selected in place long enough to "get through the learning curve" on the first couple of wells. It is difficult to improve if key team members leave too soon. Parker dedicated one senior manager, with extensive experience, as the lead member solely dedicated to the project. This decision was valuable in the evolution of techniques, equipment changes and procedures, and assisting newer members.

Results, Conclusions

Execution results were predictable. The wells were drilled with minimal downtime, no HSE incidents, and in the time frame expected. Production results are still being evaluated. Was it perfect? No, most new techniques require considerable upfront expense and refinement. Changes to UBD equipment and rigs were made on a minor scale to speed up installation / moving, but the core function of equipment / people was as per the training and expectations.

In conclusion, these points were developed and contributed to project success:

• Upfront planning, including the drilling contractor, is paramount for success.
• Include HSE personnel in the planning process. Disasters, as noted in the first example, would not have occurred had the proper reviews been made.
• Understand that UBD is not a concept easily understood by the drilling contractor, who has a different concern than the operator, but both must work together.
• Significant technical training is needed to be sure drilling contractor personnel understand the "why" of UBD and how to manage the process at the rig.
• Drilling contractors must understand the drivers for the operator, to be able to deliver the end result. These are different than what are "normal" to the contractor.

Further: compensation of the various parties must be explained and understood; a team is not a team unless all are aligned with the same goals. And when a problem occurs, involve everyone in the solution. Success is as a team, not as an individual.

New technology coupled with correct application and execution will extend the boundaries of our businesses – operators and contractors alike. UBD concepts are not new – just the application of new technology and equipment. As shown by the second example, the focus on long-term, life-cycle cost and profit can set in motion an atmosphere where the "team" can succeed. Common goals, commitments and benefits are keys that are discussed in business schools, sports stadiums and yes, at the wellsite, by those who succeed.

Acknowledgment

The authors wish to thank the management of Parker Drilling Co. for permission to publish this article, and the many field people involved in the UBD technology who have the vision for working safely, while bringing new ideas to all of us. This article was prepared from paper SPE 74445 of the same title, presented at the IADC/SPE Drilling Conference, Dallas, Texas, February 26 – 28, 2002.

The authors
	Ross Murphy, PE, General Manager, International Operations, Parker Drilling Co., is a PE graduate from Texas Tech University (1977). He has 25 years’ experience as a drilling engineer, drilling / operations manager and general manager for Amoco, Helmerich & Payne and Parker. He recently returned to the U.S. following a tour in Atyrau, Kazakhstan, as general manager for Parker, starting up the world’s largest arctic-class barge rig in the North Caspian Sea.
	Paul Thompson, Operations Manager for various offshore drilling contractors, began his oil industry career in 1978 in the North Sea, following activities as a "miner." He started as a roustabout and worked up to his present position. He has worked on land projects in Iran, Nigeria, Colombia and Ecuador. After joining Mallard Bay Drilling, later acquired by Parker Drilling Co., he worked offshore in water depths from shallow to 2,500 ft. His latest assignment was for Parker, working with BP-Amoco in Colombia on a UBD project in the Cuisiana-Cupiagua field.