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Developments with collaborative well planning

Thursday, July 4, 2013

Collaborative well planning technology is developing quickly - with better integration with other systems, data updating, and tools to help design relief wells.
By Dan Colvin and De Wayne Pratt, Landmark Software and Services


Sophisticated asset and field planning algorithms enable automated, multi-well target generation, path planning, platform or pad placement, development scenario evaluation and field-level optimization-all within the context of the 3D subsurface and/or reservoir model. (Fig.1)

Software and workflows continue to undergo significant refinement, incorporating new levels of integration, automation and optimization, new targeting capabilities, relief well planning options, and enhanced support for geosteering workflows.

Integration

Collaborative well planning technology has long been able to access data from the subsurface model.

However, in the past few years, geology, geophysics, earth modelling, and well planning have been seamlessly merged into a single E&P workflow environment based on a shared reservoir model.

The unified workspace is integrated in several important ways.

Not only can asset teams share a common underlying database, but now they can work collectively within a single multi-domain application to interpret G&G data and plan single wells, multi-laterals, or field-scale development scenarios.

Integration with industry standard GIS technology (Fig. 2) enables teams to visualize and incorporate lease maps, topographic maps, cultural data, and bathymetry to properly position wellsites and pads while avoiding 'no-go' zones, surface obstacles, and potential drilling hazards.

For rigorous trajectory optimization, anticollision, torque and drag and other critical analyses, well or field plans can still be transferred securely and seamlessly to high end, industry standard engineering software.

Automation and optimization

Patented algorithms optimize field development plans based on user-specified cost parameters, risk and uncertainty, and degree of difficulty.

Advanced automation techniques allow team members to interactively shift a target, pad or platform location, and watch the well plan update in real time.

If any user-defined design constraints are exceeded-such as kick-off point, dogleg severity, turn-drop rate or inclination-the trajectory will turn red.

Enhanced flexibility enables engineers and geoscientists to rapidly incorporate local refinement into large-scale field plans, instead of forcing all wells to use the same parameters.

Localized optimization is proving especially critical in unconventional plays, for example, allowing teams to tweak the doglegs in a handful of wells or set pad locations only on slopes of less than, say, 10 degrees.

Targeting

New targeting capabilities are making collaborative well planning technology even more valuable in tough drilling situations.

While team members can still pick reservoir targets manually within the 3Dmodel,the software can automatically generate targets in more ways than ever before.

For example, auto-targets can be based on favourable reservoir attributes.

In complex faulted environments, targets and well trajectories can be automatically placed a specified distance behind an interpreted fault plane and specified distances from one another.

For thin beds and horizontal wells in shale or steam-assisted gravity drainage (SAGD) operations, asset teams can define targets as a percentage of thickness using any two interpreted surfaces, including seismic horizons.

Recent horizontal targeting capabilities for unconventional resource plays include an option to 'fan' out the laterals (Fig.3) to improve reservoir coverage wherever parallel orientations would not align well with lease boundaries.

Targets can also be based on modelled field drainage or specific hydraulic fracture areas.

In fields with many surface constraints, well planners can actually create sites, targets and horizontal trajectories in a single click.

Relief well planning

Following the 2010 oil spill in the Gulf of Mexico, the U.S. Government now requires operators filing for deepwater permits to submit at least two relief well plans. Similar requirements are likely to be adopted elsewhere in the world.

As a result, new manual and automated relief well planning options have been incorporated into evolving collaborative well planning systems.

Obviously, no one can know in advance exactly where a relief well may need to kill an existing wellbore. Historically, some operators had no formal relief well plan, requiring them to scramble in the event of a blowout.

Coming up with a viable plan from scratch could take a full day or two, costing precious time.

Other operators generated an excessive number of intercept plans for every casing section down to total depth (TD), requiring overly expensive and unnecessary work up front.

New automated relief well planning tools (Fig.4) offer an attractive alternative. Selecting one of three different intercept methods- simple, oriented, or parallel track-and establishing a range of boundary conditions and parameters, geoscientists and drilling engineers can rapidly create a technically feasible plan, ready to tweak on-the-fly, if it ever becomes necessary.

During pilot testing with a major oil company in the Gulf of Mexico, asset teams successfully designed final relief well plans in as little as 30 minutes.

Geosteering workflows

In addition to well and field planning, multi-domain collaborative technology also supports geosteering workflows within today's unified E&P workspace.

During real-time operations, horizontal well correlation technology enables geoscientists to pinpoint the current stratigraphic position of the bit, while a look-ahead well plan indicates where the wellbore will go if it proceeds along the current trajectory.

'Automated workflow re-execution' or dynamic updating ensures that any change made to any interpreted surface in the existing 3D model-say, repicking a top or adding a new data point while geosteering-instantly revises every associated surface, while honouring all the hard data.

Thus, each new logging-while-drilling correlation automatically shifts the top and base of the target reservoir accordingly.

Targets that are now too high or low can be fine-tuned simply by moving them onscreen.

The collaborative well planning system immediately projects an updated look-ahead well path to the optimal target location ahead of the bit. Alternatively, the team can establish a set distance between the well path and any reference surface, such as the top of the reservoir.

Whenever new data points modify the structural interpretation, the software automatically revises the 3D model, the targets, and the look ahead well plan to maintain the proper distance-without any manual intervention whatsoever. As such, operators can stay in the sweet spot all the way to total depth. (Fig.5)


Off shore case study

One of the world's largest oil companies field tested the enhanced collaborative asset planning software to evaluate early development alternatives in an offshore environment with a number of seabed and shallow drilling hazards.

The goal was to select reservoir targets, identify viable drilling locations, create multiple well paths that met fracture pressure constraints, determine drilling costs based on an existing cost model, and present development concepts to partners as quickly as possible.

Utilizing a wide variety of geotechnical data, a multi-domain team set up the model in two days, automatically generated development scenarios that met all their constraints within two hours, quality-controlled the results in another four hours, and presented targets, trajectories, drilling locations, and estimated costs to partners the very same day.

The team's drilling engineer stated, 'We did in one day what could have taken a month of cross-discipline iterations and data transfer.'

Onshore case study

Operators of fast-paced, high-volume onshore drilling programs have begun to experiment with it as well (Fig. 6).An independent operator of an unconventional U.S. play was one of the first.

To effectively produce tight gas sands having limited drainage areas in the Piceance basin of Western Colorado, the operator planned to drill hundreds or thousands of wells in some rather rugged topography.

Pad locations were limited due to terrain, wildlife populations and migration pathways, and other surface restrictions-roads, power lines, lakes, wetlands, towns and buildings.

Planning huge numbers of safe, drillable well trajectories proved overwhelming. Long well planning cycles or miscalculations would have been extremely costly.

The new asset planning technology enabled the company's geologists and engineers to quickly design and optimize large numbers of sustainable well plans from restricted surface locations. They were able to keep pace with aggressive rig schedules, minimizing cycle times while maximizing reservoir coverage, enhancing production, and reducing capital expenditures.



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