Fluid & Gas Flow

New Processes Needlessly Reduce Recovery from Onshore Gas Fields, Part 4

November 12, 2014

Oil-and-gas-riskDrilling procedures and equipment have evolved over the last 150 years to the point where drillers can hit a 6-inch target a mile down and 2 miles to the left nearly 100 percent of the time. Given enough time and money, there is almost nothing that modern drillers cannot do with regard to hitting a target and a trajectory. As technological capabilities have advanced, costs have increased.

To a significant extent, drillers are the victims of their own successes. When directional drilling was more art than science, they had the latitude to do it right and consider the needs of the reservoir. Doing it right 100 times in a row caused management to begin to accept that drillers could do what they said they could do and start asking if they could do it less expensively. All of the significant drilling variable costs can be related to "time on location." Consequently, drillers started getting measured by days on location, and the drilling schedule became the controlling factor in a drilling program.

Process safety management (PSM) tells us that you must have two verifiable barriers between an energy source and workers. Carrying that concept to a wellbore says that the stripping rubbers on a BOP are inadequate protection, and you must have a second barrier. Hundreds of thousands of wells were drilled in the last century without this second barrier, and the frequency of blowouts and fires was very low. That is irrelevant. Any risk that can be reduced must be reduced under the tenets of PSM. The needs of the reservoir are not to be considered.

Drilling with overbalanced mud has the highest potential for a no-surprise, on-schedule well. Running production casing past any potential hydrocarbon zones and cementing to surface minimize the possibility of getting hydrocarbons onto the rig floor.

Soft rock like coalbed methane/coalseam gas (CBM/CSG) fails when mud is used, so lost circulation material (LCM) is always part of the pre-spud materials on location. This LCM is very resistant to flow in both directions and mud-drilled CBM/CSG wells always start out underperforming air-drilled offsets, but overbalanced mud and LCM allow the drilling department to meet safety and schedule goals that do not include initial production rate (or any other reservoir-performance-specific goal) and meet the requirements of PSM.

The cement used in wellbores is quite dense. A column of cement above a coal seam will cause the coal to fail, and cement will enter every weakness in the coal matrix. One client of mine plans on needing twice as much cement as the traditional calculations would predict. The missing cement is expected to travel into the coal for some non-trivial distance. My client asked me to help determine why these wells rarely make economic production when the gas-in-place is so high. When I explained that cementing the coal had a very low probability of economic success, their response was "our HazOp showed that air drilling the coal and producing it open hole or with an uncemented liner would have too high a potential for a blowout." Eliminating that risk was more important than the field being economic.

Completion decisions must be based on the needs of the reservoir. Conventional oil and gas wells are normally cased, cemented, and fractured. Shale reservoirs tend to be strong enough to tolerate this conventional process and cased, cemented, and fractured shale wells are approaching 50 percent of U.S. total gas production. Coal lacks the mechanical strength to allow this conventional approach. When we cement production casing across coal seams, we rarely get economic wells.

Even with air drilling and open-hole or lined-hole completions, fracking jobs are a very iffy proposition in CBM. In the messy environment of a borehole through a coal seam, it is impossible to control where a frac will go. Placing the frac string adjacent to the target formation does not in any way ensure that the fracking fluids will go where you want them. We regularly frac coal wells, but the results are far from predictable, and every good well is attributed to "a successful frac" and every bad well is attributed to "poor reservoir conditions." We keep doing frac jobs in coal seams, more because they can be done on a predictable schedule than because they work.

An alternative completion technique that proved incredibly successful in the San Juan Basin of Northern New Mexico and Southern Colorado has been "cavitation" [1. This process requires the injection of high-pressure air into the wellbore to increase the pressure in the cleats in the first few inches of coal, and then the pressure is rapidly dropped to try to expand the trapped air enough to blast the coal from the matrix and flow the solid coal to surface. This process is repeated dozens of times over several days or weeks until the coal stops flowing.

The results in San Juan show that a well that is able to cavitate will outperform a similar well that is not cavitated by a factor of 10 to 40 times (e.g., a well that would yield a 10 MMSCF (million standard cubic feet)/day rate cavitated will make something between 250 and 1,000 MSCF (thousand standard cubic feet)/day not cavitated) and a cavitated well will outperform a similar well that is cased, cemented, and fracked by 50 to 100 times. The purpose of the industry would say "if a well will cavitate, you must cavitate it."

There are a number of companies developing coals that would have a high potential for successful cavitation. Generally these wells are completed with either open-hole, non-cavitated completions or they are cased, cemented, and fracked. One company says that the reason for not cavitating is that the required duration of the procedure is quite variable and "[cavitation messes up the rig schedule." Another says that the reason for cementing production casing across the coal is that it is "company policy." Neither rig schedules nor outdated policies have considered the optimization of profit from the reservoir.

Wellwork is another area where the industry has lost track of reality. Historically it was common to pull tubing from a producing well by setting a plug in the tubing and stripping the tubing out of the hole. This has been done millions of times with success.

Today's risk intolerance requires a second barrier, so kill-fluid is pumped into the wellbore to pull tubing. Some reservoirs tolerate this very well and return to production after wellwork with minimal disruption. Other formations struggle. As reservoir pressure comes down, the frequency of wells not recovering from kill-fluid increases. The CBM wells in the San Juan Basin Fairway generally have reservoir pressures under 100 psia (689 kPa). At that pressure, the ability of the reservoir to overcome waterlogged flow-channels in the near wellbore is quite limited. Killing one of these wells has the tendency to reduce gas production to near zero for months or even forever. But PSM says that stripping tubing out of a live well is simply too dangerous to be considered.

Finally, wellbore jewelry has gotten very risk intolerant. One of my clients was experiencing significant lost production due to liquid loading in a tight-gas field. My first question was, "What is the pressure on the annulus?" The response was that there is a packer and the annulus is full of annulus fluid. In a gas well, access to the annulus for pressure monitoring and for flow during deliquification evolutions is critical to success. The answer to the packer question was "company policy, we must have two boundaries between the reservoir and uphole aquifers; the annulus fluid ensures that we know if there is a casing failure." This environmental risk intolerance will result in decreasing ultimate recovery in this field to about half of expected levels. There really isn't any way to recover from these choices. Most intervention tools available later in life require access to the annulus.

[1. Palmer, I.D., Mavor, M.J. et al, Openhole Cavity Completions in Coalbed Methane Wells in the San Juan Basin, SPE 24906, Journal of Petroleum Technology, Volume 45 Number 11, November 1993


David Simpson, P.E., is the owner and principal engineer at Muleshoe Engineering. David is an MVP in the professional forums at www.eng-tips.com and is a member of the Engineering Writers Guild. This article was originally published on Engineering.com and is adapted with permission. For more stories like this please visit Engineering.com.


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