The continual delivery of consistently improving performance and efficient operations in the many diverse global petroleum plays can provide significant challenges to both operators and service companies. Although it is relatively easy to establish a status quo for performance and be satisfied when nothing goes wrong with an operation, it is a very different proposition to drive a process of continual improvement that may briefly increase the risk profile as new approaches are tried.

As each performance enhancement is delivered, the next set of challenges to overcome continues to increase in complexity, and potential solutions become fewer. Options also are restricted by the economic constraints associated with the exploitation of hydrocarbons across the spectrum of well and reservoir types, limiting the solutions that can be developed and deployed.

The capability to identify the specific requirements of each unique situation is only effectively achieved through the creation of experienced multidisciplinary teams. An engineering solutions team with the right blend of abilities can identify the factors limiting performance and develop the most effective answers.

Halliburton’s response to this market need is the creation of Drilling Engineering Solutions (DES) teams to develop this ability in key geographical locations globally.

Performance improvement opportunities

Opportunities for increasing the performance of an operation can be classified in three ways, including risk mitigation that prevents failures and cost overruns, drilling efficiency that decreases the required expenditure and improves the capital efficiency and improvements in the productivity of the well or field.

The development of a strong engineering capability for both planning and delivery is needed, with teams of domain experts who can analyze the drilling behavior and develop new designs as well as field engineers with specialist training in interpreting surface and downhole measurements.

Risks created by unplanned events or conditions, rather than those that are expected, are mitigated through delivering the required wellbore trajectory and reducing positional uncertainty. This type of risk mitigation includes survey management and controlling drillstring dynamics, vibration and stress overload to prevent premature failure of equipment and reduced drilling performance. It also includes determining the wellbore integrity and in situ wellbore pressure boundaries and managing the hydraulics system to remain within the wellbore pressure boundaries and deliver effective hole cleaning. All of these requirements need to be managed effectively to maximize the average ROP.

Drilling efficiency opportunities occur most often during the planning of the well, in which the single best well design and equipment are selected from many options. At this stage, the previous performance is analyzed, the factors limiting efficiency are identified and solutions are developed; both technical and economic feasibility is assessed. Fluids, drilling systems and drillbits can be custom-designed for the expected conditions. Managed pressure drilling and underbalanced drilling feasibility studies can be performed and procedures and best practices created for the operation.

Productivity improvements can be delivered through improved planning and during execution. Planning the most efficient field drainage pattern with the minimum number of pads or wells will decrease the overall cost.

Understanding the reservoir geomechanics to orient the reservoir sections to maximize fracture potential or minimize the sanding potential will increase the total production from the field. Geosteering the wellbore to maximize the reservoir contact and drilling wells underbalanced to reduce skin damage will improve the production per well.

The Halliburton software platform DecisionSpace Well Engineering contains commercial engineering modules and has been devised by Landmark to enable the development of plug-in modules. This capability enables individuals to develop their own software applications containing proprietary capabilities and have them work in the same software framework and access the same database.

For the DES teams, an application called DrillingXpert has been developed on the DecisionSpace Well Engineering framework providing full access to all of the commercially available and Halliburton-proprietary analytical software tools and planning databases used by the solutions teams.

Performance improvement in action

A steam-assisted gravity drainage well pair placement had the potential for future infill drilling and needed to maintain the wellbore quality within softer unconsolidated formations.

The planning phase required a detailed analysis for the trajectory designs and the application of survey management to perform quality control to reduce the uncertainty of the wellbore positions. This need also extended to the geosteering modeling that is required. It also was necessary to ensure that the correct LWD tools were selected to determine the proximity to the reservoir boundaries while maintaining bottomhole assembly (BHA) directional performance.

The wellbore integrity analysis required the development of methods to maintain the stability of the oil sands while drilling. The bit design must resist abrasion from drilling the sands, maintain ROP and be matched to the BHA for directional performance. The BHA design required that it could deliver a wellbore with minimum tortuosity while steering effectively in the unconsolidated formations.

The project required that a minimum of a 3-m (10-ft) standoff was to be maintained from the reservoir base and that a smooth wellbore was delivered with less than 3 deg/30 m (3 deg/98 ft). Tortuosity would be minimized through no overcorrections while maintaining extremely tight injector/producer steering windows; a 5-m (16.4-ft) offset would be maintained between the injector and producer wells.

In addition to the geometric constraints, the geology also played a significant role. The reservoir sands are part of a fluvial-dominated estuarine complex, and the base reservoir is rarely flat for any appreciable extent, with 1-m (3.3-ft) to 3-m localized variations being common. Consequently, the modeling of tool responses in this environment was required. To improve the detection of bed boundaries, an azimuthal resistivity tool was selected as the best measurement.

The reservoirs in question consisted primarily of bitumen that will flow when heated. Mud coolers were used to maintain the drilling fluid temperatures to be as close to the virgin reservoir temperature as possible. Temperatures of about 20 C (32 F) were maintained, which then controlled the choice of the elastomer used in the motor power sections and the choice of oil used in the rotary steerable system (RSS).

Additional limitations were imposed by the rig, with surface revolutions per minute (rpm) limited to 60. The use of long-gauge bits with a point-the-bit RSS was proven to deliver a considerably higher hole quality than the use of a motor or of push-the-bit systems. In this case, a RSS powered by a downhole motor was selected to meet the trajectory challenges and to provide greater bit speeds without exceeding the 60-rpm surface limit.

BHA design modifications

Further modifications of the BHA design were required. The RSS was customized for the softer formations with extended-reach rollers added to the reference housing. The second modification was the addition of a lower housing stabilizer to help compensate for hole enlargement. If the formation compressive strength is less than the fulcrum force, the hole will enlarge until the forces balance, reducing the build/drop capability of the tool.

This design moves the fulcrum point back from the bit to the stabilizer, which is nonrotating, reducing the hole enlargement because there is no side cutting. The final modification is the upper stabilization optimization, which resulted in significantly lower cumulative doglegs and greater consistency in reducing the doglegs compared to conventional mud motors.

To maintain the distance above the base reservoir, an azimuthal resistivity tool was used. The tool assigns the resistivity measurements into 32 bins to provide an up-and-down resistivity measurement that has significantly more character than an averaged measurement in determining distance to bed boundaries.

The tool has three frequencies, enabling it to identify bed boundaries up to 5.5 m (18 ft) away, and under ideal conditions it has greater vertical resolution and accuracy in high-resistivity formations. Using this type of measurement will map out the base reservoir surface for the entire lateral section as compared to shallower reading measurements in which intermittent identification of the reservoir surface is obtained.

To improve the data rates for these additional sensors and to send commands to the rotary steerable tool, electromagnetic (EM) telemetry was used. EM telemetry also has the benefit of not requiring a differential pressure to function. Active ranging, where an EM signal is emitted from the target wellbore, was used both to twin injector and producer wells and to range wellbore positions to the observation wells, which are important when modeling the life of the reservoir and the effectiveness of the steam injection.

To manage and successfully deliver all of the elements of this engineered solution, an established and documented diagnostic approach is necessary, which includes a formalized engineering process that crosses multiple disciplines and determines the interaction of different experts.

Establishing a dedicated organizational capability ensures a rigorous adherence to procedures while providing the level of integration to design fit-for-purpose drilling systems and establish consistent connections between planning and execution.