Australian coalbed methane fields can yield lessons for US shale producers

Nick Heyes
Accenture
Brisbane

Marco Merino
Todd Blackford
Accenture
Houston

The rapid growth in unconventional fuels–ranging from shale oil and gas to coalbed methane–has dramatically increased the complexity of field development and production management.

Instead of placing a few large bets on a few wells and drilling rigs–and watching those bets very closely–operators now must deal with multiple wells, conflicting equipment priorities, and capacity limits for water and steam. They must determine which wells to drill and when to drill them. They must coordinate rig and crew counts while balancing the requirements imposed by lease restrictions and capital constraints.

Low oil prices leave operators with very little margin for error. As they seek to balance production volumes against changing prices, US operators looking for an edge can benefit from the experience of their Australian counterparts, who have dealt with complex coalbed methane (CBM) operations in Queensland for years.

Australian CBM operations have been described as the most active development of unconventional gas resources outside of North America, and production is increasing rapidly. Several multibillion-dollar projects have been announced in Australia, with gas exports principally aimed at markets in Asia. The CBM industry has attracted some of the largest international oil companies.

In Australian CBM operations, methane from coal seams is recovered by drilling a series of primarily vertical (but also some horizontal) wells directly into the seam. Water must first be drawn from the coal seam to reduce pressure and release the methane from its adsorbed state on the surface of the coal and the surrounding rock strata. Once dewatering has taken place and the pressure has been reduced, the released methane can escape more easily to the surface via the wells.

The methane will be converted into LNG for export. This entails making volume commitments that must be met under any circumstances. Estimates are that as many as 36,000 new wells may be needed to support these LNG projects. In this environment, operators typically run a high number of rigs and move the rigs around. The timeframe from assembly of the rig to production of a well is as little as 5-6 days. Equipment, drilling supplies and crew availabilities are all at a premium.

The complexity of the coal methane gas operations–as well as the high velocity at which drilling is undertaken–mean that field development planning is of paramount importance. Fast, accurate modelling is crucial, and the right tools in terms of data and software make all the difference. At the same time, the productivity of each well varies significantly making field production rates difficult to estimate.

Given the large number of wells, traditional methods of estimating in-place gas, for example, by removing core samples for analysis or well-logging can be cost prohibitive. Porosity varies from basin to basin and from coal seam to coal seam, complicating the task of estimating economically recoverable reserves.

In our work with Australian CBM operators, we have identified a number of key capabilities needed for unconventional energy operators to make the most of opportunities as they present themselves:

• Flexibility. Asset teams should be able to make quick decisions about the drilling plan and other operational concerns. Asset teams also need immediate access to decision-making tools. Spreadsheets can manage these inputs up to a certain level of complexity, but with the drilling of new wells and management of workovers of existing wells in a development that might have thousands of wells operating at any one time, the need for new tools becomes evident. With the right tools to enable flexibility, it becomes easier to shift rigs to the most economically desirable locations as needed.
• An integrated view. New tools enable planners to create a detailed, comprehensive model of their fields and development opportunities. Such an integrated view incorporates daily well scheduling, facilities construction, and transportation plans as well as an economic engine. Modelling can capture critical assumptions such as type curves, well counts, locations, rig and resource availability, water capacity, capital costs, price forecasts and many other elements. The "view" can become real in the form of visual representations of the entire operation and the interplay between and among various factors.
• Near-real-time tracking. Tracking original forecasts versus actual results is essential, but it is also important to be able to track daily spending. Output, once tracked daily, can now be tracked hourly, providing an almost immediate feedback loop. This monitoring is particularly important today given the low and volatile oil prices and decisions of when to drill vs. when to complete, so that production decisions can be closely coordinated with development decisions.
• Insight into the future. In the Australian CBM business, the emphasis is on identification of risks and rewards from the outset, with careful analysis of sensitivities and uncertainties. Short-term production forecasting provides insight into the order in which wells are drilled and into expected production based on the constraints imposed by people, wells, capital and other considerations. LNG projects, supplied by CBM fields, need production certainty, so forecasts of "ramp gas" are produced even before the LNG plant is complete. Unconventional oil and gas fields in North America may be more organic, but this view into the future remains valuable.

Underpinning all these capabilities, Australian CBM operators work hard to ensure that field personnel can easily, efficiently, and accurately order, schedule, deliver, and confirm operational services. They strive to automate the manual processes involved in ordering services, coordinating and confirming their delivery, and processing and paying invoices. Any potential bottlenecks are systematically identified and, if possible, eliminated.

Optimized planning boosts revenue

One of the biggest benefits from taking this approach to field-planning development comes from connecting development planning with production management. Our experience has been that optimized planning produced more revenue for the same–or lower–capital investment.

By integrating development activities with production activities, operators can coordinate production operations maintenance and workover scheduling with development scheduling. The ability to respond rapidly to changes in the field allows for planning and optimization on a daily basis.

This minimizes disruption and provides better data and analysis, leading to better decisions about applying capital to operations such as whether to boost output from producing wells. The increased information flow helps to quickly spot underperforming wells so the asset team can put corrective plans in place.

For example, Enersight Corp. was involved with work in Australia for execution planning, production forecasting, development optimization, asset budget, and scenario analysis. Information deployed in a cloud environment allowed for a reduced implementation life cycle and the project delivered:

• Accurate modeling of the project’s surface physical network with all nodal constraints.
• Value chain physical flow for gas and water.
• The upstream component of the operator’s business plan.
• Improved development planning and production optimization.
• Short term production forecasting capability integrated with the long term forecast.
• Cross-functional scenario analysis capability for identifying de-bottlenecking and other value adding opportunities.

The big advantage to connecting development and production, however, is that people working in the field get to see the big picture while providing quality input all the way up to the corporate level. By managing the convergence of production, maintenance, engineering and finance at all levels of the enterprise–increasing transparency into all processes and functions–unconventional oil and gas companies can shorten the time between decision-making at the management level and execution in the field.

Applying lessons elsewhere

Many US and Canadian unconventional operators are large, sophisticated operators, and they have adapted elements of integrated field planning already being used in Australia. Recent volatility in oil and gas prices underscores the need for capital and operational efficiency. Some producers still use spreadsheets to analyze complex production variables, while others rely on manual processes at various links in the supply chain.

As a first step, large-scale unconventional oil and gas producers can take an inventory of current business and data-management processes ranging from forecasting and modelling to production to transportation. Chances are such an inventory will reveal practices that may have seemed acceptable in an environment of sustained high prices, but now need to be addressed. Undertaking this initiative in an integrated, top-to-bottom fashion can help the unconventional oil and gas producer meet commitments while optimizing financial performance.

The authors