Converting resources to reserves ­– enhancing return on investment with drilling and evaluation technology

Most industry experts agree that to successfully meet the world’s rapidly growing demand for oil and gas, new technologies will be needed. This article illustrates what innovative oil companies can do right now to enhance and accelerate production through the use of novel, yet proven , technology and drilling practices. In particular, this article reviews three main challenges namely drilling hazard mitigation, well bore placement and reservoir quantification and examines some of the approaches used to address these challenges on a complex well in a mature basin.

Effects of non-productive time on project economics

In drilling environments with high daily operating costs, as is the case with most offshore rigs, the most visible impact of Non -Productive Time (NPT) is the escalation in well construction cost s. However, the impact of NPT reaches much further than this and applies in a similar manner to low drilling cost environments. Any delay in getting the well drilled adds risk, as the exposure time of geological formations to the drilling fluids, either Water -Based (WBM) or Synthetic Oil -Based Mud (SOBM) , is increased. The interaction between the mud system and the rock formations can result in the onset of irrecoverable instability and, in the worse case, ultimate loss of the well. Longer exposure to the (over-pressured) mud will cause near- well bore damage to the rocks, creating an additional barrier that will reduce the reservoir’s producibility. In addition, NPT delays production. Whether or not the well is being drilled in a production sharing agreement, the financial impact of this is significant both in terms of lost production as well as contractual implications towards meeting supply contracts to utility companies or other end users. NPT also delays the time which the next rig can spud the next well. In new developments, the cumulative effects of NPT stretch out over the entire project, reducing the number of wells that can be drilled in a given time frame. In mature field development s, where decline rates are increasing, this can affect the ability of the operator to maintain production above economic thresholds.

Causes of non -productive time

There are numerous ways of classifying and evaluating NPT. From one perspective, NPT is considered as any time that the bit is not drilling new formation . This include s commonly considered NPT categories (i.e., rig repairs, waiting on weather, downhole tool failures , etc , ) as well as everyday activities such as pulling dulled bits, running and cementing casing, wireline logging and more. Basically, some consider NPT as any “ flat time” on the time-depth curve . NPT can account for between 20 to 40% of total well construction time . As such, it represents a considerable cost and time savings opportunity.

For the purpose of this discussion, we will focus on NPT associated with formation related drilling hazards and drilling tool reliability . Together, these two categories can make up as much as 50% of NPT, with the larger share often attributable to drilling hazards, such as unstable or over-pressured formations, shallow fluid flows etc.  

Non -productive time and well bore stability

Up to 40% of all NPT relates to well stability issues, caused by formation stress and pore pressure issues. As wells have become longer and more complex in terms of 3D geometry, stresses around the well bore can vary radically while drilling. Approximately one in three wells proposed in the Middle East and S outh -E ast Asia cannot be drilled as planned due to the complex local stress regime and narrow pressure window between fracture and collapse. Mitigating this risk requires a pre-well model, constructed from offset well and seismic data, to determine the best mud weight and well plan to manage stability. Field studies show that extensional, compression and strike-slip settings all occur and in some cases fields only 40 kilometres apart can see rotations of 90 degrees in the primary stress direction. Real-time, while-drilling , monitoring and updating of the stability model is key to drilling the technical limit in this highly dynamic environment.

Information required to do this comes in two forms. The first relates to rock mechanical properties, such as Young’s modulus or Poisson’s ratio which can be derived from advanced LWD acoustic measurements and direct measurements of the formation pressure. The second is a direct observation of the way the borehole responds to the drilling process. Azimuthal calipers measure the shape of the borehole and high definition LWD images detail drilling-induced fractures and incipient breakouts. By updating the model, changes to the mud program , and in some cases drilling angle , can be made to prevent costly NPT incidents.

Non -productive time and tool reliability

To reduce NPT, one of the challenges faced by the drilling and evaluation service provider is to constantly improve the reliability of the Bottom Hole Assembly (BHA). This applies even when the BHA systems deployed are becoming increasingly complex to simultaneously meet more demanding objectives – drill faster, drill more complex wells, drill to smaller targets, drill in more demanding environments , deliver a wide spectrum of formation evaluation answers in real-time, etc. A holistic approach should be taken to enhance reliability, as it is affected by all functional groups along the entire supply chain from design, through manufacturing, maintenance, job planning and operation.

Once deployed in hole, the objective is to optimize drilling performance by protecting the system from damaging vibrations while simultaneously maximizing Rate of Penetration (ROP). To achieve this, a n advanced downhole drilling dynamics service can provide real-time, expert analysis of downhole weight-on-bit and torque-on-bit, BHA bending moment, whirl and pressure diagnostics in addition to the standard stick-slip and vibration measurements. This not only enhances drilling performance, it lowers operational risk and improves overall borehole quality by allowing engineers to actively avoid potentially damaging, yet otherwise unseen, downhole events.

Well bore positioning in complex environments

The concept of maximizing well bore contact with the reservoir is not new, but the technology to achieve this goal has advanced greatly in the last few years.

• The approach used by the client in th e following example can be broken down into several stages.

The first stage is in well planning. Previously, horizontal wells have been subject to large uncertainties in vertical position with targets not well defined in 3D-space . This led to shorter well sections and poor control of well placement over a field. Using a rigorous well planning process that visualization of the 3D geological structure, coupled with advanced survey corrections , the asset team assure d development of a well plan which me t all their primary objectives.

Technology for achieving the plan

A well plan might fulfill all geological objectives, but can it be drilled? Modern rotary steerable technology is designed to drill complex well profiles in a smooth and precise manner to minimize tortuosity. The secret behind this is an intelligent downhole closed-loop process, which automatically updates steering vectors to maintain the planned well path with the minimum of human intervention. Complex 3D profiles such as 360 ° flat turns or extended reach dragon wells are no longer consigned to the wish list. In this example, the well was steered through the reservoir, turning just over 400 degrees around the structure to expose the maximum possible area of drainage, as shown by the yellow well path in the figure. The addition of a high powered drilling motor to the rotary steerable system delivered additional energy directly to the drill bit, overcoming rig torque limitations and minimizing potential wear on casing and BHA while still retaining pinpoint closed-loop drilling accuracy.  

Correct drill bit selection, designed to compliment the performance of the rotary steerable system ensured maximum steerability and penetration rates while minimizing vibration . Borehole stability and quality was achieved through the use of an optimized drilling fluid program. Having a single service provider plan these together can often be advantageous.  

However, just because a well plan can be drilled does not mean it will be successful. Geological structures below seismic resolution and subtle variations in rock properties can often turn a sure winner into a mediocre producer.

Assessing the plan

Several measurements may be needed to determine if the plan is being followed and more importantly if it can be improved while drilling.

A challenging profile such as in this example often means that there is very little margin fo r error between the desired rate of turn to intersect the target zones and the physical limits for successfully running casing or completion strings. This presents a challenge, as hitting strong formation dips or tightly cemented zones can often deflect the bit temporarily, creating micro-tortuosity that doesn’t allow completion strings to be run. By monitoring the BHA bending moment in real time, any slight deviation can be detected and remedial action taken before a problem occurs.  

Ensuring that the well is in the “sweet spot”, i.e., the best reservoir interval, is determined depending on what characteristics define that interval. If the zone is defined on a geological basis then correlation using gamma ray and resistivity measurements may be enough. If the zone is defined by a set of rock properties, such as a formation porosity, permeability or pressure, then more complex measurements are required. These can include compressional and shear acoustic measurements to better define the type of porosity in the case of fractured or vuggy rocks, or formation pressure measurements while drilling to delineate reservoir compartments and fluid contacts and allow for better completion string design.

To avoid early water breakthrough, the well path may need to be a certain distance from the water zone . This can now be achieved with new technology in the form of deep-reading azimuthal resistivity measurements. Azimuthal resistivity can also delineate the shape of the reservoir or enable ‘terrain tracking’, where the well skims inside the attic for maximum recovery. In this technique, a boundary up to 5 metres away from the well bore can be detected as long as there is an appropriate contrast in resistivity.

Of course, bed topology and bed dip are not always the same and knowledge of both can often help position the well most effectively. Flow direction and architecture of channel systems, bed dips within a slumped unit all the way down to subtle cross-bedding and fractures can be resolved using LWD imaging.

• In th is example, real-time LWD density imaging was used to characterise and analyse the changing dip pattern. As the well was drilled around the reservoir, the apparent dip of the formation changed significantly. With interactive 3D well planning software and real-time dip analysis , geological surfaces and well log information were interpreted simultaneously , optimizing the well path in the reservoir.

Converting the large quantities of data received into useful information requires that the right people get the right data at the right time. Modern fibre optic and satellite links allow for client and service company expert centres to receive and process data in real-time. Relying on the service company expertise to support operations with detailed analysis and interpretive products enables clients to focus on the critical decisions.

Quantifying the reservoir

Once the well has been drilled and maximum reservoir contact achieved , the next question to be answered is what and how much will the well produce? In addition to a challenging directional profile, the evaluation of this particular well required a complex set of measurements , as unusual mineralogy adversely affect ed the standard density and porosity measurements. In stead, porosity and movable fluid measurements from LWD Nuclear Magnetic Resonance (NMR) technology were required to properly quantify productive zones that would have been mistaken for non-productive intervals due to the complex mineralogy.

Conclusion

Whether the mission is exploring and developing a field with only one well, or drilling the optimum pressure support pattern, by having an answer to critical challenges while drilling, the chance of success is significantly higher.  

Drilling hazard mitigation and well placement management require real time information, making the use and development of new LWD technology essential. There is more, however, as advanced drilling and evaluation technology not only makes complex wells possible, but improves profitability too. Benefits include

• accessing stranded reserves
• increasing production
• extending the productive life of wells
• increasing recovery factor.
• In the case where multilateral and/or extended reach drilling techniques are employed, there are also improvements to the environmental impact of field developments.

The demand for oil has accelerated new technology development, extending the end of the ‘oil age’, and as long as this trend continues, oil companies willing to use technology to push the boundaries will continue to reap the rewards by converting hydrocarbon resources to reserves.