UNDERBALANCED DRILLING

The changing face of underbalanced drilling technology

Part 1 – Principal components of conventional underbalanced drilling (UBD) packages, including the Flow Back, Injection and Data Acquisition systems

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

nderbalanced drilling technology and techniques have changed significantly over the past five years. Gone are the days of choosing liquid / gas blend ratios based on flare appearance, or collecting inflow data on the backs of cigarette packages. The role and interdependence of individual companies providing discreet services has become clearer with time. In order to drive this technology into the next phase of development, service providers must integrate UBD services to a level not previously achieved.

The overall theme of this article series – integration of UBD equipment and management – is covered in three parts. Part I, presented here, discusses – component by component – a conventional package of UBD equipment and defines the operating systems required, internal to each component.

In Part II, the authors will discuss the interrelationship between components and illustrate how systems integration can be implemented. This will include the advantages and challenges system integration poses – from process control, through data acquisition, to training and safety issues.

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. This final article will conclude with a discussion regarding some current advancements in UBD technology. The merit of interactive data acquisition / equipment control systems – as well as data acquisition and its relative link with real-time, multiphase flow (steady state and dynamic) and reservoir inflow modeling – will be considered.

Introduction

The material comprising this series was not written to form the definitive informational package regarding UBD equipment. The author’s objective is to provide enough information to clearly state basic component functionality and discuss the interrelationships of components from a system-integration perspective.

A differentiation should be made between the two basic system-integration types. One type of integration exists at the business-management level only. This arrangement is characterized by a common presiding element which provides a single-point contact between service providers and customer. The presiding element can either take responsibility for accounting functions only or can, in addition, take operational responsibility, thus focusing risk, reward and accountability upon itself. External project-management groups have provided this service in the past without capital interest in equipment.

The second way to integrate service providers exists at a systems-control level. Each component required to drill an underbalanced well is directly linked to the others through a macrocontrol system or, at the least, through a combination of control systems and operational procedures. The synergy between individual components is recognized. Philosophically, the ultimate integrated system by which all others should be measured is the arrangement that concurrently focuses on both business-management and systems-control levels.

A comprehensive analysis of where UBD system integration is going must be prefaced with a discussion of where the industry is. The following sections discuss where controls integration exists in a conventional UBD system, beginning with the Flow Back System, followed by the Injection System; a brief note on Data Acquisition completes the discussion.

Flow Back System (Fbs)

This system typically includes the: flow cross, flow diverter, emergency shut down (ESD) valve, flowline, choke manifold, sample catcher, phase separation vessel(s), shipping pumps, flare line and the flare stack, Fig. 1.

Fig. 1. Flow Back System on a conventional UBD package.

Flow cross. This is the first piece of ancillary equipment coupled with the rig’s primary well control system. Supplementary or redundant well control is provided by the UBD Flow Back System. The flow cross is a flanged spool with one or two flanged outlets and is typically located between the drilling rig’s uppermost spherical preventer and the flow diverter, Fig. 2. The flow cross, by design, does not lend itself to controls.

Fig. 2. UBD stack, including flow diverter and flow cross.

Flow diverter. This component is typically installed at the top of the BOP stack, above the flow cross, Fig. 2. Its primary function is to direct returning fluids away from the rig floor. Fundamentally, there are two types of rotating diverters: passive and active. Selection is based on planned tripping procedures, acceptable failure mode and desired level of control.

Fig. 3. Flow diverter, passive system.

Passive systems include any diverter that effects a seal through a rubber-to-steel friction fit between the element and the drillstring, Fig. 3. Energy to maintain the seal is provided by tension in the rubber element and upward-directed flowing well pressure. A positive seal across tool joints is maintained without the need to regulate sealing pressure.

Some disadvantages are associated with handling bits and near-bit tools. The bearing assembly must be "hung" on a collar (or drill pipe section) prior to recovering the bit or irregular-shaped tools, e.g., stabilizers. Further, rubber packoff elements are under significant tension and, therefore, seal failure is swift once a tear, e.g., cut by sharp kelly edges, has been initiated. Controls are limited to bearing lubrication systems and do not interact with other UBD components.

Active systems rely on external hydraulic energy to effect a seal between the element and the drill pipe interface, Fig. 4. A hydraulic regulator is required, since the force that is needed to effect a seal is constantly changing due to changing cross-sectional area. An advantage of active systems is associated with recovering bits and near-bit tools. Regulator pressure can be decreased and the bit will drift without removing the element or bearing assembly. A possible disadvantage related to active systems is coordinating the rig and active diverter’s regulator pressures as changing cross-sections pass through each packoff area.

The operating system required for an active system is very similar to that of a rig’s BOP system. An oil reservoir, accumulator and pumping system, along with hydraulic controls, are required. While active systems require more sophisticated internal systems control than passive systems, they are still typically stand-alone packages that do not interact with other UBD components.

Fig. 4. Flow diverter, active system.

Emergency shut down valves (ESDs). These components are remotely activated by flange valves (typically gate or plug) mounted directly to a manual valve that, in turn, is bolted directly to the outlet on the flow cross. ESDs are functioned when there is an unplanned release of well returns caused by a breach in the FBS. Typically, this would be the result of a washout in the choke manifold. ESDs can be actuated directly by air, hydraulics or electric signal over hydraulics. They are normally designed to fail closed or in last position (frozen).

Most often, controls to the ESD are located at three different locations in the vicinity of the gas separator. Functioning the ESD is usually the responsibility of the FBS operators. The driller and other onsite vested parties are authorized to close the EDS, but typically do not have conveniently located controls at their disposal. The driller must, therefore, communicate (via radio) to FBS operators, anyone’s wish to function the ESD.

The primary function of the ESD is to protect personnel and equipment downstream of the wellhead. The ESD should never be functioned when a diverter rubber fails. Operation and activation of ESDs is typically a stand-alone function that does not interact with other UBD components.

Flowline. This line forms the conduit by which well returns are routed from wellhead to the choke manifold and the phase separation system. Critical considerations of flowline design include sizing, connections, geometry and pressure rating.

Flowline diameter must be large enough to handle anticipated return rates. Frictional losses must not exceed backpressure constraints dictated by the reservoir pressure. Hammer unions or flanged connections are used to connect flowline joints.¹ Sharp bends should be avoided to minimize erosional washing. The flowline should be designed to a working pressure equal to the weakest link between flow diverter and chokes (inclusive).

A conventional UBD system does not have controls on the flowline which interact with other components. New designs aimed at severe-service and/or offshore applications have incorporated a control system that toggles well flow from one flowline to the other through interconnected ESD logic.

Choke manifold. Underbalanced drilling choke assemblies utilize various choking devices – annular, fixed bean, adjustable – and they come in a number of configurations. Chokes are used when flowing pressure from the underbalanced well exceeds safe vessel working pressure. Presumably, multiphase flow modeling will have calculated appropriate injection-blend ratios that will control reservoir inflow and thereby minimize surface flowing pressure – however, other constraints may dictate that backpressure is necessary. Choking return flow on connections and trips may be required to either keep production from displacing the drilling fluid (high-energy gas wells) or – as in the case of prolific oil wells – artificially charge the annulus to avoid loading to reservoir-pressure equilibrium.²

Choke assemblies are laid out in either parallel or series configurations. The traditional drilling-type configuration – three flow paths in parallel – utilizes an adjustable choke and fixed bean on the two outside paths and a through-line "gut" down the middle, Fig. 5. The adjustable choke can be manually or hydraulically controlled. Another common configuration utilizes hydraulically controlled, rubber, annular chokes plumbed in series. In either case, an operator must manually set the choke position to maintain the desired pressure drop. The chokes themselves may have internal control systems to regulate the hydraulics, however, the setting function is independent of the other UBD components.

Fig. 5. Typical UBD choke manifold.

Sample catchers. The role of the sample catcher is simple in theory, yet difficult to attain. They come in a variety of types and pressure ratings but essentially function in identical fashions. A portion of the flow from the wellbore is directed through a chamber, where mesh screens catch returning solids but allow gas and liquid to pass. The screens must be fine enough to catch a representative cuttings sample, yet coarse enough to exert minimal backpressure.

Position of the take-off is critical to the design. For most wells, the entire return flow cannot be diverted through the chamber, therefore, relative fluid velocities and solids momentum will determine the sample cut. The take-off cannot be at a right angle to the flow path, or the solids will bypass. The process of catching samples currently has no control system and does not interact with other components.

Pressure vessel / phase separation system. There are numerous techniques currently used to effect phase separation, primarily governed by two distinct strategies: 1) all phases are separated simultaneously in a single vessel, or 2) each phase is separated in sequence in a series of vessels.

In the first strategy, drilled solids, liquid hydrocarbons, water and gases (both methane and nitrogen) are returned to a single, four-phase separation vessel, Fig. 6. The velocity drop at the inlet to the vessel results in an efficient division of gas and solids phases in the first compartment. Liquids cascade over to the back compartments where, with sufficient residence time, an interface is formed. The disadvantage of this system is vessel weight and size. The vessel is built large enough to attain residence time for liquids and thick enough to perform gas separation under pressure.

Fig. 6. Conventional four-phase separator.

In the second strategy, separation is achieved in a series of vessels designed to separate the phases sequentially. The order in which phases are separated may differ between systems. The schools of thought are:

• Gas should be separated and sent to flare first, since it is compressible and significantly lower in density than liquids or solids and relatively easy to separate. Remaining liquids and solids can then be shipped to atmospheric facilities where they can be dealt with using conventional drilling fluids-separation technology. Solids can be removed at a shale shaker or centrifuge. Liquids can be separated in a cascading-tank system.
• Solids should be removed first since they erode the piping as they accelerate through the Flow Back System. Optimal location of solids-removal equipment is upstream of the choke manifold, where pressure is the greatest and flowrate is lowest. The solids can be removed in a high-pressure, vertical knockout vessel or high-pressure hydrocyclone. The remaining phases are separated downstream of the choke manifold in a pressure vessel and cascading-tank system.
• Gases, liquids and solids are separated at flowing pressure in a suite of purpose-built hydrocyclones connected in series, parallel or a combination of both. Since the hydrocyclones would be rated to flowline pressure, the choke manifold would not be necessary. This may be the preferred configuration if injection into existing pipelines and avoidance of re-compressing produced hydrocarbon gas is desirable. However, it is important to note that effects of high flowing pressure at surface must be reconciled against allowable, resultant bottomhole flowing pressures.

To date, the vast majority of separator systems are operated manually. They rely completely on separator personnel to monitor fluid height in vessels and to ship fluids.

Shipping pumps. As an alternative to moving liquids using pressure in the pressure vessel, shipping pumps can be used to transport drilling fluid to the suction tank and produced fluid to the storage facility. Shipping pumps are typically centrifugal in design, with impellers matched to separation-facility, flow-through criteria. For the most part, shipping pumps are functioned manually, but some float-activated systems are in use.

Flare line and flare stack. The line leading from separation facilities to the flare stack is usually 152–305 mm (6–12 in.) in diameter, based on vessel pressure rating. Much like in sizing of the flowline from wellhead to separator, backpressure due to friction must be considered. The flare line contains a backpressure valve that maintains a desired pressure on the pressure vessel. Additionally, the flare line can be manifolded to allow gas to feed a pipeline compressor. Neither of the functions is commonly process controlled.

The flare stack is the termination of the gas-separation process. Produced gases are burned at the flare stack. The stacks are usually 152–305 mm (6–12-in. in diameter and vary in height from 3–30 m (10–100 ft), depending on expected production rates and gas composition. Automation of flare stacks is limited to the auto-ignition function and pilot-flame maintenance. Flare stacks are typically stand-alone packages that do not interact with other UBD components.

Injection System

The gas injection system typically includes: high-rate / low-pressure screw compressors, membrane nitrogen-generation system, positive-displacement reciprocating compressor, mud pumps and chemical-delivery system, Fig. 7.

Fig. 7. Injection system on a conventional UBD system.

Gas injection system. Many options exist regarding type of gas injected to lighten a column of fluid and facilitate UBD. Produced methane, membrane-generated nitrogen, cryogenic nitrogen and scrubbed exhaust gas are the primary options available.³ Decisions to utilize one gas instead of another are usually based on availability, volume or rate required for operations, cost and chemical compatibility. This article does not attempt to discuss the merit of one gas over another but, rather, will focus on points common to the pumping of any gas.

A high-pressure line must be rigged into the high-pressure, rig-pumping system so that the gas can make its way to the drilling tubulars. Typically, valves and check valves are manifolded to: allow gas injection into the liquid phase, allow bypass of gas to the standpipe and provide a means to bleed off the energized drill pipe when a connection is performed, Fig. 8.

Fig. 8. UBD injection manifold on a conventional UBD package. Courtesy Flow Drilling Engineering.

Experience has shown that gaining consensus from various instruments measuring injection gas can be quite difficult. This may be of lesser concern, since injected gas rate is typically not nearly as strong a function (regarding bottomhole pressure) as injected liquid rate.⁴

Rate and on/off controls related to injection gas are limited to regulators (in the case of existing sales gas), pump speed (in the case of cryogenic nitrogen) or compressor speed (in the case of membrane-generated nitrogen and scrubbed exhaust gas). In all cases, service operators must manually shut down / bypass, or set, feedrate. Operation of compressors or feed sources is typically a stand-alone function that does not interact with other UBD components.

Aqueous phase / mud pumps. Experience has shown that utilizing a rig’s mud pump during UBD may not be appropriate. Rig pumps are sized to drill several different sections, with typical flowrates varying from 500–1,600 lpm (132–423 gpm). UBD flowrate criteria typically range from 75–350 lpm (20–92 gpm). To meet these lower injection rates, operators must often mobilize rental or add-on, high-pressure, low-rate pumps. Rental mud pumps usually have local controls only, thereby complicating communication between driller and rental pump operator. Functioning of mud pumps (off/on, rate control) is traditionally a stand-alone function performed by the driller (or rental pump operator) that does not interact directly with the functioning of other UBD components.

Drilling rig mud tanks. Rig mud tanks play an integral role in fluids handling on most underbalanced systems. After gas has been separated from the flowstream, solids and liquids are shipped back from the separator to the drilling rig shaker box for solids separation and fluid holding. Data concerning total volume on surface are typically combined by manually adding rig pit volume totalizer (PVT) data and separation provider’s data.

Chemical injection system. These systems work at high or low pressure and are used to inject precise rates of liquid chemicals into either the return stream (high- or low-pressure side) or the injection stream (high pressure). Common chemical additives to return flowstreams are methanol, corrosion inhibitors, oxygen scavengers and defoamers. Common chemical additives to injection flowstreams are corrosion inhibitors, oxygen scavengers, drilling fluid additives (caustic soda, liquid polymers) and foamers. Chemical-injection systems are typically simple systems in which the suction side of air-actuated, high-pressure diaphragm pumps is rigged directly into the supplier’s chemical containers, and the discharge side is rigged directly into the flowline.

Since different applications require different chemicals to be injected, there are often several discreet injection packages working on a rigsite, by different persons. Complications can arise, since certain operations may require the cessation of injection of one chemical (by one service provider) and the continuance of another (by a different service provider). For example, during a connection, chemicals injected into the injection stream should be shut down to avoid pumping a slug of chemical down the drill pipe when pumps are brought back online.

During this same period, the well may be flowing, and it may be desirable to continue pumping other chemicals (methanol, defoamers) into the return stream. Functioning of chemical injection pumps (off/on, rate control) is, traditionally, a stand-alone function performed by various service providers that do not interact directly with the functioning of other UBD components.

Data Acquisition System

In the first few years of UBD, service providers recognized the need to acquire data as it related to their own equipment (or service), but did not recognize the importance of integrating data from an overall-project perspective. As time progressed and the technology was better understood, it was clear that – to properly engineer / execute underbalanced projects and provide comprehensive daily and end-of-the-well reports – it was necessary to integrate the data into all-inclusive packages.

Pioneer UBD engineering / project-management companies recognized this need and addressed the issue of correlating and presenting the data manually. The first step was to visit each service provider and request that their CPU be zeroed to a common, agreed-upon time. From that point forward, data from production testers, gas compression (and, therefore, injection), directional, fluid pumping and the rig could be correlated through a common timeline. Relationships (through graphing) between parameters could then be investigated and diagnostic observations and recommendations could be made, Fig. 9.

Fig. 9. Sample diagnostic plot, gas production rate and TVD vs. MD. Courtesy Flow Drilling Engineering.

Eventually, existing companies with data-acquisition experience began offering total data-management services. Data Acquisition and integration became synonymous. Data-acquisition services have traditionally been supplied by discreet companies specializing in data management. Integrated service companies are moving toward supplying comprehensive data-gathering capabilities.

Acknowledgment

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, October 27–28, 1999.

Literature Cited

1. Alberta Energy Resources Conservation Board (ERCB) Interim Directive 94-3.
2. Teichrob, R., Husky Oil underbalanced drilling procedures, 1993.
3. Butler, S. D., A. U. Rashid, R. R. Teichrob, "Monitoring downhole pressure and flow rate critical for underbalanced drilling," Oil and Gas Journal, September 1996, pp. 31–39.
4. Teichrob, R. R., H. J. Abdul, S. D. Butler, "Reservoir inflow while underbalanced drilling – A qualitative perspective," paper 97-138, presented at the CADE/CAODC Spring Drilling Conference, Calgary, Alberta, April 8–10, 1997.

The authors

R. R. (Bob) Teichrob, Product Line Manager," Underbalanced Drilling, Tesco Corp., Calgary, started working on drilling rigs in 1976, and after drilling for a few years, went back to school and earned a BSc in PE. He began working for a major Canadian oil company as a drilling engineer and drilling superintendent. In 1994, he spearheaded the formation of Flow Drilling Engineering Ltd. (FDEL), a registered engineering company focused solely on engineering / project management services to UBD projects. FDEL joined Tesco in 1996 and formed a new division for UBD engineering and design / fabrication of integrated UBD packages, Mr. Teichrob is a registered professional engineer and is a member of the Canadian Land-Based Well Control Examination and Certification Committee and the IADC UBD Modeling Sub-committee. He has authored or co-authored several technical UBD papers, and he presents drilling technology lectures at the University of Calgary.

David Baillargeon, Engineering Manager for Tesco’s Integrated Services Division, obtained a bachelor of applied science degree in CE from the University of Waterloo. Presently, he is responsible for a team of engineers that provides office / field support for the UBD operations at Tesco; he has 16 years of drilling experience in both operations and service sectors, holding drilling engineering positions at two Canadian oil companies and a drilling fluid specialist position at an international oilfield service company. Mr. Baillargeon is a member of SPE, the Canadian Association of Drilling Engineers and the Canadian Institute of Mining.

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