The changing face of underbalanced drilling

R. Teichrob

Part II–How components for drilling underbalanced are tied together through macro-control systems/data acquisition, crew structure and training

Part I of this series described many of the key components required to drill an underbalanced well. At the end of each component description, a short statement discussed internal control systems and their relationships with other UBD components.

This article will demonstrate how the various UBD components required to drill an underbalanced well have been tied together through macro-control systems/data acquisition, crew structure and training. The model on which the text is based is Tesco Corp.’s Integrated Underbalanced Drilling Package.

Part III will illustrate the concepts with a long-term case history (1994 through 1999) of the continuing development of a Northern Canadian, pressure-depleted gas reservoir utilizing UBD technology. The presentation will discuss early UBD techniques and demonstrate how package/system integration has led to significant savings in drilling time and money. It will conclude with a discussion regarding some current advancements in UBD technology.


Two objectives must be met when designing an integrated UBD system. The first is to bring all equipment required to drill an underbalanced well together into a cohesive package and “charge out” on a single invoice. The second is to recognize interrelationships of the various equipment suites and tie all of the equipment together through control systems and standard operating procedures (SOPs). Control of some essential elements would be extended to the driller via a Driller’s Control Panel.

Tesco Corp.’s Integrated Underbalanced System was designed to pump and accurately measure extremely low fluid rates/volumes, supply electrical power (including heating energy when required), maintain reduced active system volumes and employ state-of-the-art control technology, Fig. 10. The rig would essentially be delegated to hoisting duties only. Building a UBD package in this fashion removes the uncertainty of relying on varying rigs for external power, liquid pumping and handling duties. The learning curve associated with rigging up the UBD package to differing rigs could be avoided, and cost benefits, e.g., move and rig-up time, could be passed along to the customer.



To demonstrate the level of system integration and control, it is best to follow elements of fluid and gas through the entire injection and return circulation systems, under steady-state drilling conditions. After this–in the following section–typical connection procedures and the required communication loops for both nonintegrated and integrated UBD systems are outlined.

Injection system: Liquids, gas. For liquids, starting at the closed drilling fluid tank, an element of fluid is moved through a centrifugal precharge pump to the low-volume, high-pressure triplex mud pump. Volume data is collected from the drilling fluid tank and sent to the centrally located Programmable Logic Control (PLC) system. This data is used to determine (at any time) total volume of liquid at surface which, in turn, is used to perform material balance calculations. If liquid volume in the closed tank and pressure vessel, and liquid hold-up in the well are known, gain or loss of fluid over time can be determined.

Both precharge and triplex pumps are electrically driven and controlled through PLC technology. When the triplex is switched on, a precharge pump automatically starts. The triplex is functioned (on/off) by a remote switch located at the Driller’s Control Panel. Pump rate is set by a senior underbalanced system operator at a local touch screen at the PLC control panel. The rate is attained and maintained by a feedback control loop and a micro-motion mass flowmeter. The PLC program adjusts rate by varying pump speed based on mass-flowmeter data.

To remove the uncertainty of hydraulic efficiency and accurately determine fluid-injection rate, a micro-motion mass flowmeter was mounted on the suction side of the triplex pump. Since a known rate of liquid enters the pump, it follows that the same rate leaves.

The PLC program recognizes pump inefficiencies through constant comparison of actual and calculated (based on pump speed) output. When speed reaches a maximum (typically 10% over calculated), an alarm sounds and the problem is investigated. Regardless of pump speed, a known rate of liquid is introduced to the well. The mass flowmeter also supplies the PLC with a fluid density that can be used by the engineers to interpret wellbore events.

The element of fluid has now passed from a low-pressure, [approximately equals] 500-kPa (72-psi) suction line to the high-pressure injection line. Located directly at the output side of the triplex pump is a data header which collects pressure and temperature information that is sent to the PLC. A chemical-injection header is also located at this point. Programed chemicals are introduced to the high-pressure injection stream by a set of high-pressure, ultra-low-volume, chemical-injection pumps. The chemical-injection system is a permanently-mounted, tank/pump package that has limited control through PLCs.

The liquid passes along a length of high-pressure line until it meets with a Y. At this point, the injection gas, usually membrane-generated nitrogen, is commingled with the aqueous phase, forming a two-phase mixture which is routed to the rig’s standpipe.

For gas, starting at the intake to the screw-type compressors, an element of air is pulled into the compressor, and its pressure is increased to 1,400 kPa (203 psi) from 100 kPa (14.5 psi). The discharge is fed to the Nitrogen Production Unit (NPU). The NPU utilizes a series of filters to knock out liquid and solid particulates prior to entering the membrane modules. Oxygen is stripped from the air and vented to atmosphere. The remaining gas–essentially nitrogen with 2 to 5% oxygen by volume–is routed to a reciprocating booster, where the gas pressure is increased from 1,200 kPa (174 psi) to standpipe pressure.

Boosters are typically rated for either 17,500 kPa (2,540 psi) or 35,000 kPa (5,080 psi). The discharge is routed to the Y for combination with the liquid phase. On/off control of gas injection is located at the Driller’s Control Panel, and the flowrate is set at the local touch screen at the PLC control panel. Gas-injection rate is measured by a Versibar solid-state, gas flowmeter and is controlled by the PLC through a feedback loop with the booster’s drive engine.

Appropriately-placed check valves ensure one-way flow of both gas and liquid. The two-phase fluid–along with desired chemicals–is now directed to the drilling-rig standpipe for injection down the drillstring.

Return system. Well returns comprise the injected fluids (gas and liquid), drill cuttings/hole cavings, hydrocarbons (gas and/or liquid) and possibly formation water. The flow diverter seals the wellbore and directs well returns, first through the flow cross and then through the ESD. The hydraulically-controlled ESD can be functioned manually from a station located at the UBD control panel, or it can be functioned from a number of remote stations through an electric switch–including a switch at the Driller’s Control Panel.

In conventional systems, the driller must request that the triplex pump and nitrogen-injection systems be taken off line–to avoid pumping against a shut-in, flow-back line–when the ESD is functioned. When the Integrated Package ESD is functioned at the Driller’s Control Panel–or any other station equipped with electronic switch–a signal activates the PLC program, which shuts down the triplex injection pump (along with the precharge pump and certain chemical injection lines) and diverts the nitrogen feed stream away from the standpipe. This brings the entire UBD system to a safe operating condition while eliminating need to verbally communicate with discreet-service providers.

From the ESD, returns are routed through the choke manifold into the pressure vessel. A fraction of the returns is sent down a sideline to extract cuttings samples. The pressure vessel separates most of the gas and coarse solids. Solids are sparged and shipped by a progressive cavity pump for processing. External, electronic sightglasses in the pressure vessel send fluid levels to the PLC. High and low levels, as determined by percentage volume, are set on the PLC control panel.

When fluid level in the vessel gets to the input high level, a centrifugal pump/valve assembly is actuated and fluid is shipped until the fluid reaches the input low level. At this point, the centrifugal pump/valve assembly closes and the vessel begins to fill again. This self-regulating system allows the fluid level in the vessel to be maintained accurately with little human intervention.

Once the gas has been separated, the remaining liquids (oil/water) and solids are processed through a bank of hydrocyclones, where fine solids are removed. Remaining liquids are then directed to the closed and vented drilling-fluid tank for gravity segregation at atmospheric conditions. The liquid phase used for drilling is fed to the triplex precharge pump for re-injection, and produced hydrocarbons are shipped to remote storage facilities.

All shipping lines have in-line flowmeters. Data from these is sent to the central PLC, where flowrates are converted to volumes and integrated into the overall material balance. The gas element is routed to either a conventional flare stack or an existing sales-gas pipeline.


For conventional systems, the typical connection procedure shown here illustrates shortcomings of the nonintegrated system. Radio communication is excessive, opportunity for miscommunication increases and a hazardous environment is created. In such procedures, the:

* Driller alerts all separation and gas/fluid/chemical-injection personnel by radio that a connection is forthcoming

* Driller radios fluid-injection operator “shut fluid pump down”

* Pump operator radios back “pump shut down”

* Driller continues to pump nitrogen until drillstring purged to uppermost float in drillstring

* Driller radios gas-injection operator “shut down (or divert) nitrogen”

* Gas-injection operator radios back “nitrogen shut down”

* Driller hoists pipe to set slips and prepares to add new drill pipe joint

* Driller radios gas-injection operator “bleed off pressure”

* Gas-injection operator radios back “bleed off open, pressure bleeding off”

* Energized drill pipe is bled off and driller makes connection

* Driller radios gas-injection operator “close bleed-off valve”

* Gas-injection operator radios back “bleed off closed”

* Driller radios fluid-injection operator “turn fluid pump on”

* Pump operator radios back “pump on”

* Driller radios gas-injection operator “bring nitrogen on line”

* Gas-injection operator radios back “nitrogen on line”

* Driller runs to bottom and goes back to drilling.

In the integrated system, the Driller’s Control Panel simplifies the procedure, In this improved system, the:

* Driller alerts the UBD crew that the connection is forthcoming. He then executes all steps

* Fluid pump is switched to off

* Nitrogen is pumped until drillstring is purged to uppermost float

* Nitrogen feed is switched off

* Drill pipe is hoisted, slips set and a new joint is prepared to be added

* Kelly bleed off is switched to open

* Connection is made

* Kelly bleed off is switched to close

* Fluid pump is switched to open

* Fluid pump is switched to on

* Nitrogen is switched to on

* Driller runs to bottom and goes back to drilling.

When a connection is made, virtually all radio communication is avoided. The procedure is greatly simplified. Developing the Driller’s Control Panel has successfully integrated some of the driller’s duties directly into ongoing operations. Ambiguity regarding operation of specific equipment has been removed.


Managing an underbalanced project in the field has always provided both technical and operational challenges. Technical challenges will always be present and, essentially, are driven by outside forces, i.e., reservoir pressure, potential inflow and its characteristics, technology available to cope with special need, etc. Root-cause challenges in operations can often be found in communications–both between the foreman and various service providers, and between the service providers themselves.

Where this becomes painfully obvious is during pre-spud/pre-drillout and safety meetings. The typical scenario in nonintegrated packages is that each service provider has a crew represented by a supervisor. The foreman communicates his instructions to perform a task to each supervisor who, in turn, passes orders along to subordinates. The foreman must then ensure that all service providers understand their role and also understand the potential impact that each has on another. Experience has shown that this can be frustrating for foremen familiar with UBD operations and nearly impossible for those who are not. A modification to the crew structure has alleviated this problem for an integrated system.

The integrated crew structure is predicated by all disciplines reporting to a single person, i.e., the drilling service supervisor (DSS) who, in turn, reports directly to the foreman, Fig. 11. The model by which the crew structure was put together can loosely be compared to that of a typical drilling rig, with the toolpusher at the top of the organizational chart.


Communication of operational issues from a macro sense is streamlined. The DSS is responsible for all the UBD equipment onsite and communicates operational reports to the foreman who, in turn, can concentrate on managing the drilling of the well.

Challenges that became evident when building a crew to the above template were numerous but not insurmountable. A primary challenge was to source individuals with production testing, compression and drilling backgrounds. It was found that individuals with drilling and testing, or drilling and compression backgrounds were available, but individuals with backgrounds in all three disciplines were difficult to find.

Another challenge was to instill a common mindset that equipment operators were no longer drilling, testing or compression operators, but were indeed a new hybrid–underbalanced drilling operators. To facilitate this development required crosstraining and a reassignment of individuals to positions to which they were unfamiliar.

Crosstraining was paramount to the success of the new structure, and it added value by enhancing troubleshooting capabilities and creating a personnel pool from which new drilling service supervisors could be promoted. Intimate knowledge of the drilling rig and the interrelationship of the UBD package permitted faster identification of problems as they occurred, and more-informed recommendations regarding problem mitigation, e.g., downtime of the first integrated package (after commissioning) was less than 1.5% during the first six months of operation. An added benefit of fully crosstrained crews was that crew members could substitute for each other as needed.

One of the major benefits of adopting this realignment was that safety programs could be implemented which effectively considered all services and their impact on each other. Each service provider had done a commendable job of implementing their own safety program, but could not formulate an overall safety program based on macro-UBD operations. The process of creating HAZOP studies and bridging documents with operators is simplified by the existence of integrated safety programs.


Regarding project accountability, since all services are integrated into one discreet package, the operator should no longer identify problems/issues with specific service providers and attempt to factor out the role other services may have played. A single-point contact enables the operator to discuss issues/ concerns with the drilling service supervisor, leaving little room for miscommunication or ambiguity.

Cost control. A common complaint among operators is that they are obliged to pick up operating rates (or possible standby rates) for the remaining underbalanced drilling spread when one piece of equipment fails. The cost risk can be better defined when all services are tied together and presented through a single invoice. If one component fails, no charges for peripheral equipment should be levied until the overall package is up and operating again.

Implementing continuous-improvement programs. A common goal of operators and contractors is to implement and demonstrate continuous-improvement mandates. In the past, realizing this goal has been difficult for a number of reasons. Defining job roles–and attendant accountabilities–and understanding the interrelationship between service providers can be difficult. End-of-well reports help, but typically are focused internally in discussing what the service provider could have done, or avoided doing, to contribute to the project–from their perspective.

These individual reports do not generally discuss recommendations regarding other service providers, since companies are either unqualified or reluctant to comment (possibly jeopardizing their relationships). An integrated package must, by definition, look to the bigger picture and how all the individual components perform as a whole.

The first two parts of this series indicate that there are still opportunities to improve. There are a number of components that lend themselves to process control and the interaction with other components that remain as standalone. Obviously, more control and more interactions are possible, but the value added must be weighed against cost to design, build and maintain. Until operators take on more complex underbalanced projects, where precise drilling parameters are required and sophisticated techniques are employed, the automation and “intelligence” of systems may not be developed.

As noted earlier, the concluding, Part III article will illustrate the concepts with a long-term case history from Northern Canada, and conclude with discussion of some ongoing UBD technology advancements.


The authors would like to thank AEC East for their valuable contribution to the case study, and the management at Tesco for supporting this work and permitting its publication. This article was prepared from the paper of the same name, presented by the authors at the IADC Underbalanced Drilling Conference & Exhibition, Netherlands Congress Centre, The Hague, Oct. 27-28, 1999.

R. Teichrob, P. Eng., Tesco Product Development; and D. Baillargeon, P. Eng., Tesco Integrated Services, Calgary, Canada

COPYRIGHT 2000 Gulf Publishing Co.

COPYRIGHT 2000 Gale Group

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