WELL CONTROL

Well control: Past, present and future

Where we are and where we’re going with technologies for understanding downhole well control while drilling

Colin Leach and David Schwartz, Well Control & Systems Design Inc., Houston

his article identifies the various technical components of well control applied in the process of drilling. Two tables summarize the evolution of well control approaches from the past to the future and some specific technical advances that are now available.

The text emphasizes control techniques in the annulus around the drill pipe. The important point is made that industry is moving toward the ability – and the need – to integrate engineering packages with new, "visualization" geological packages for a complete downhole picture. Equipment issues are not discussed here; the authors believe these are best addressed separately.

Introduction

Significant changes have occurred in the processes of well control, and further leaps are being made. Table 1 summarizes where we have come from, where we are now and where we are headed. There are some significant differences between these three phases. In the "Past," industry experts recognized that they did not understand events in the annulus and that methods had to rely on the drill pipe side. Today (Present), events in the annulus can be understood, although industry is not yet taking full advantage of this understanding.

In the "Future," we will fully grasp this understanding of the annulus and be in complete control of flows / pressures within the well, i.e., we will be able to pinpoint the operating condition for the well. In addition, there will be a much better tie-in to geological information – probably in the form of "visualization." Together with effective pore pressure / fracture gradient determination, this will allow final mastery of the subject.

The requirement to upgrade technology from the past and improve further is driven by:

1. Drilling wells in which the margin between formation and fracture pressure is small. Such drilling may be termed "drilling the limit." In some cases, the margins are small because of naturally occurring pressures or because of previous production operations – in these wells, there is little choice for the driller. In other wells, drilling with smaller margins allows the number of casing strings to be reduced – here, there is very much a balance to be made in risk vs. reward.

2. Drilling wells in which there is a requirement to drill below, at or just above balance to limit potential reservoir damage – for these wells, the simple, straightforward well control methods may not be applicable.

There are many wells that are still drilled where neither case 1 nor 2 above drives the technology. In these wells, the established approaches to drilling and well control are perfectly valid.

For the future, there will be more focus on maintaining a precise bottomhole pressure (BHP). This will become possible with the full integration of pressure while drilling (PWD) and real-time (transient) hydraulic and kick models, and the availability of effective pore pressure / fracture gradient determinations. There may also be the requirement to go to full-automatic choke and pump control. The combination may result in significant drilling cost savings, as non-essential casing strings are removed. And it may also result in improved well productivity, as less damage is inflicted during the drilling phase – effective well control is a byproduct of this process.

Finally, there is the opportunity to integrate the engineering packages with new, "visualization" geological packages. This will allow matching up the engineering choices (margins, for example) with the geological formations. Given that the engineering possible today can virtually remove all engineering risk, this puts the risks fairly and squarely on the shoulders of the geologist and the unknowns concerning formation depth / pressure.

Whereas all of this is possible – and in the not-too-distant future – it is possible that change may not happen as quickly as it could because of "narrow thinking" on the part of the industry. In particular, well control is sometimes considered to be the means to deal with kicks. As there are relatively few kicks – and in most cases, the financial cost of such an incident is relatively small – there is little interest in making improvements. However, if the subject is viewed in the light of what it really is, with the ultimate goal of providing "Precision Balanced Drilling,"* then the benefits are enormous, and the industry would be correct in supporting the required technologies at an appropriate level.

*(A trademark of Well Control and Systems Design.)

Past And Present

Table 2 provides a listing of some of the more important advances that are now available. The comparison is not quite as clear cut as the table shows, because there have always been individuals who are capable of clearly understanding annulus events. However, our present technology allows for realistic analysis to be used in conjunction with this understanding – a very powerful combination.

The past: Drill pipe methods. Drill pipe methods have been – and still are – relatively effective, because the vagaries of the annulus can be ignored. The simple goal of any such method is to maintain BHP above that of the formation and thus prevent an influx (or further influx); there is very little control, if any, on pressures in other sections of the well. In addition, the method will almost certainly result in some overpressure; which is OK as long as there is sufficient margin between fracture gradient and pore pressure at the weakest exposed section (not necessarily the casing shoe) and there is no damage caused to the formation productivity by such an overbalance.

Present: The annulus. For deep water / water-based mud, the "driller’s method" is used to remove gas quickly from the wellbore and thereby reduce potential for hydrate formation in the BOP. The drill pipe method would suggest the "Wait & Weight" method. This can be done because:

• It can be shown that pressure at the casing shoe is likely to be the same, whether the Driller’s or Wait & Weight method is used – gas migration plays a large role.
• The cooling rate of mud / gas mixtures can be effectively determined and, therefore, the time frame whereby hydrates will not form can be estimated.

   Deep water / Sweeping the Stack. For water-based mud, it can be shown that, in very deep water (>3,000 ft), it is not necessary to "sweep the stack" as long as there is no oil in the system and as long as any gas is allowed time to migrate. Precautionary note: A decision to eliminate sweeping the stack must be carefully considered for each well / rig system evaluated.

   Ballooning / Flowback in deepwater and HPHT wells has been a significant issue. At this time, it is possible to critically look at wellbore pressures during circulating and static conditions. Given this information, remedies and pragmatic procedures become readily apparent, i.e., "what if" games can be played on the computer rather than using an operating drilling rig.

   "Explosive unloading" is the term that describes what happens when a small (undetected) pocket of hydrocarbon gas is circulated to surface with no surface backpressure and using OBM. The gas stays in solution until immediately below the rotary table and then flashes off – a high gas rate can also result in some noticeable ejection of mud from the annulus. This situation has been modeled and is understood; a very realistic model is required to provide an accurate picture. Remedies for this situation are possible and, given potential risk of a major incident, must be put in place.

   Dual Density / Mud Lift Systems are targeted for introduction into deepwater drilling in the next couple of years. In these systems, the rig is effectively transported to the seabed such that the drilling mud pressure line can run parallel between formation pressure and fracture pressure lines, rather than constantly intersecting the latter – requiring multiple casing strings, as is the case with the present-day (above-sealevel) conventional system. Recognition of the issue and provision of a solution is fairly and squarely due to understanding of the pressure regime within the annulus.

It can be seen that the research and development put into this area has had significant economic impact. It is also true that trying to predict benefits of the R&D is difficult, if not impossible.

The Future

Some of the future is already here. In many cases, however, it is not used on a consistent basis, and gaps do presently exist. For example, pore pressure / fracture gradient prediction is not yet perfect. However, full pressure control of the annulus is currently within grasp, and there is no reason why this should not be the normal mode of operation within a few years. Figs. 1 and 2 compare what can be done to the current, "normal" mode of operation. In particular, the figures indicate that there is potential to impact both the underlying (static) pressure, and the dynamic pressure that is then imposed upon this static pressure.

Fig. 1. Pressure (snapshot) vs. depth.

Fig. 2. Pressure at depth vs. time.

Visualization is a means to integrate the geologic, pressure and drilling professions. This will help, because the scenarios to be looked at are too complex, i.e., for simple analysis, there are so many competing issues that we can’t tell which factor is more significant. Comprehensive computing power is required, and a basis on which the various professions can communicate is also required. Integration of geological and drilling data will allow for:

• Multiple "moving" targets during the drilling of exploration wells, i.e., targets adjusted as drilling data comes in
• Full risking of the drilling process in real time; this will answer the question: Should we drill ahead another foot, or is it time to set casing? A key to this will be the ability to closely match engineering margins with the geological prognosis.

Information will have to be available in a "real time" format for consumption at the wellsite. The complexity of the situation will also require more reliable (unmanned) instrumentation – this will certainly require more resources to be put into the drilling process. Automatic control is probably required for many of these operations; this will allow finer adjustments to be made, and consideration of multiple data inputs. There is no reason why automatic control should not be implemented on a rig – after all, we often land at Heathrow in fog under complete auto pilot.

Cost Of The Technology

Development and use of this technology is probably not justified by "better well control." There are so few well control incidents now that it is hard to justify a whole new approach to reduce them further. In this respect, though, applying what we do know to existing systems is essential to maintaining the current low level of well control incidents, and it would probably reduce this level even further.

By contrast, the cost of the new technology will be more than paid for by resultant improvements in drilling efficiency, e.g., reduction of operational downtime, and by potential reservoir productivity increases as less damage is inflicted. Improved well control will simply be a byproduct.

Conclusions

We are moving toward a scenario where geologist / pore pressure engineer / geophysicist / reservoir engineer can set a "tramline," within which, drilling operations can take place. The lower line may be the formation pressure, or it may be the formation collapse pressure (bore stability limit). The upper line is the formation fracture pressure.

We are already capable of drilling within such a set of tramlines, although the drilling process is not often presented in this way. This approach to drilling could be termed Precision Balanced Drilling. The benefits of such an approach will be significant – particularly in reducing the number of required casing strings – but perhaps more so in reducing producing formation damage. The resources required to succeed in such a venture are also significant. These resources are certainly not justified if the only gain is to improve well control, but that is not the issue.

The authors suggest that the ideas noted here will be in common use by about 2008. We are experienced with the Dual Density development – which was outlined in 1985 – but have allowed for an increased pace of change.

The authors

Colin Leach, founder of Well Control & Systems Design Inc., attended Cambridge University, England, where he earned bachelor and master degrees in chemical engineering. Training in West Texas and the Gulf of Mexico, he became a wellsite drilling supervisor with a multinational oil company. Later, he worked as a London-based PE with a major independent. This included supervision of DP wells and management of a North Sea well. In Houston from 1984 to 1993, he was a staff engineer with a major company, responsible for supporting worldwide drilling operations, particularly deep water, HPHT, well control and subsea well design. He has published numerous papers and holds three patents.

David Schwartz obtained a BS degree in PE from the University of Pittsburgh. He served in the U.S. Army as CO of a petroleum lab in Germany. After leaving the Army, he spent 15 years in the upstream oil industry as a production / reservoir / completion / drilling engineer and manager. In 1973, he joined Conoco as a drilling specialist. There he held positions of drilling manager in London and Stavanger, and managing well systems for the Hutton TLP, drilling / completions, and marine / Arctic. Before joining WCSD, he worked with Martin-Decker Totco in 1994 in sales / marketing and as product manager for new drilling data systems technology.