We live in interesting times

In 2010, production technology focused on efficiency and management. Many technical innovations helped operators get more value out of the wells they already operated. This was true in virtually every sector – land, offshore, conventional oil and gas, unconventional oil and gas, subsea wellheads, injection, and even disposal wells. Improvements have been made in almost every area. Some are obvious. For example, there has been a sea-change in the industry to horizontal (or highly-deviated) wells. More rigs are drilling these wells than are drilling traditional vertical or slightly deviated wells. More production is the result.

Yet the switch to lateral production wells introduced a whole new set of completion and production problems to be solved. Such issues as flow assurance, sand management, stimulation design, and conformance control became more critical because so much of the well bore lay in the producing interval.

A subset of lateral completions that presented critical challenges was formation treatment. Both hydraulic fracturing and matrix acidizing benefited from major improvements in technology and techniques.

Subsea production also brought new challenges and new solutions, principally in subsea processing and boosting, metering, automation, and flow assurance.

And public concerns regarding the environmental effects of hydraulic fracturing coupled with a shortage of frac water launched major campaigns to address these issues.

The far-reaching effects of one particular well that got away from its operator are yet to be assessed, but there is little doubt that the rules of the game never will be the same as a result. Each of these issues can be characterized as a “production milestone” moving into the second decade of the millennium.

Well placement becomes a science
One might think that landing a lateral production section in a shale gas well would be a simple task because, after all, shales are massive homogeneous bodies, are they not? In fact, shales have sweet spots just like other reservoirs. But unlike other reservoirs, shale sweet spots are infinitely more difficult to identify. Hard experience has proven that well placement is a precise science, no matter what formation is targeted.

Many of those who pioneered the placement of lateral production sections have learned that log results cannot simply be extrapolated from vertical pilot holes into the lateral section with certainty that they will encounter exactly the same geology and petrology when they get there. They also have learned that lateral geomechanics differ from that of the vertical pilot hole. There are swarms of natural fractures to be dealt with, and variable regional stress patterns affect the performance of perforating guns and hydraulic fractures.

Part of the problem is internal. It is difficult to convince a driller to invest in logs and cores, the value of which might not be realized until the completion is designed and implemented. Why invest the time and money in a rotary steerable geosteering system to drill a shale gas well when a mud motor and bent sub will drill a perfectly good lateral? Why care about anisotropy?

The transition from hydromechanical drilling to scientific well placement is proceeding, albeit slowly, as more and more learn that detailed advance reservoir knowledge is perhaps the best, if not the only, way to assure maximum productivity. Old habits die hard, and many still are learning that penetration rate alone is a poor metric for efficiency. Which is better, a well that drills at 60 ft/hr (18 m/hr) but uses several bits to drill each section, or a well that drills at 30 ft/hr (9 m/hr) but can drill from casing shoe to casing shoe on a single bit? Leading operators are changing their parameters to look at total drilling days and nonproductive time instead of penetration rate. The switch has encouraged bit and drilling fluid providers to invest in valuable research that targets the new metrics.

How will the well flow?
For 150 years, oil producers have lived with flow issues. Production impediments such as wax, sand, and water have plagued wells from the beginning. Lately, operators have had to deal with far more insidious threats, including asphaltenes, hydrates, and scale. First, operators learned how to deal with undesirable elements in the flow stream. Separators, desanders, and degassers were developed that did a reasonable job under optimum conditions. But recently, there has been a shift from mitigation to prevention.

Geological, geomechanical, and petrophysical measurements can tell producers if and when sanding or flow assurance issues will affect a particular well later in its life. They also can provide production parameters such as reservoir pressure change. Armed with this knowledge, operators can deploy production technology to forestall the appearance of these undesirable materials, or at least delay the events. One operator in Malaysia found that performing detailed petrology testing of production samples could save millions of dollars annually in chemical inhibitors by identifying precisely those wells with a threat of flow assurance problems instead of treating all the wells the same.

Similar analyses have been performed on wells to determine their propensity to produce sand. Appropriate limits were placed on production parameters such as flow rate or downhole flowing pressure to prevent sanding from the outset. Alternatively, sand control media were designed into the completion. Operators that take these steps are rewarded by fewer production problems and lower operating costs. Flow assurance has become a major business that stretches from prediction through prevention to mitigation.

Formation treatments become technically complex
The ancient techniques, labeled “pump-and-pray” by early adopters, have evolved into vast numbers of opportunities to improve well production performance. At the heart of a good completion is preplanning and solid engineering design. One operator in South Texas said, “I have learned that an effective frac is not just about how many tons of sand are pumped, it’s about how the well performs afterward. I give my business to the companies that recognize this and help me design my treatments accordingly.”

Treatment design starts with knowledge – the more the better. This can include whole core, offset well data; detailed geomechanical, geological, and petrophysical data from logs; seismic; and real-time LWD data acquired and used as drilling and completion progress.

Once the formations comprising the target reservoir have been characterized properly, effective completion designs can be implemented. With foreknowledge identifying the risks, the zones with the highest production potential can be treated and preventive techniques can be implemented. Frac fluid chemistry can be matched to the specific task and proppant packs can be optimized. Pumping schedules can be designed, with the understanding that real-time monitoring by microseismic fracture mapping could call for immediate changes to be made to achieve desired results. Strategic deployment of diverters based on real-time microseismic observations can literally “steer” the fracture to maximize reservoir contact. Aggressive new techniques such as batch completions on multiwell pads, “zipper fracs,” or “simul-fracs” offer advantages made possible by real-time measurements.

The new technology is not limited to new completions. An entire scenario of re-fracs has been launched in many basins, based on data from production monitoring at the wellhead and from downhole with permanent gauges or production logs.

Field, wellhead processing improves production value
Often enabled by sophisticated new flow measurements and production monitoring, new separation and boosting technology has been deployed. The most advanced is found in subsea fields. This equipment must operate flawlessly for the life of the well or reservoir. Flow can be measured and characterized, and poorly performing wells or even sections of wells can be isolated or re-stimulated. Downhole or seabed separation and reinjection saves millions of dollars in lifting and disposal costs. Irregular flow regimes such as gas slugging can be detected and mitigated before it reaches the production facility at the surface.

Often, real-time production monitoring can bring great value by enabling operators to manage their fields by focusing on the exceptions to the norm. This has been demonstrated on major, high-rate fields offshore as well as on thousands of land stripper wells. In Latin America, success stories are emerging on dozens of issues from redesigning surface power supplies on pumping wells to reduce power consumption to using real-time electronic field and reservoir management techniques instead of traditional pumping and gauging reports that took weeks to record and analyze. Electrical submersible pump longevity has been boosted by the implementation of economical downhole sensors that record and transmit pump and well performance parameters in real time to a central monitoring facility. Not only have potential pump problems been identified in time to minimize downtime and collateral damage, but well performance can be optimized by remotely changing pump speed to maximize the power factor.

Safety, reliability must be addressed
The recent loss of a deepwater well in the Gulf of Mexico has cast an unpleasant light on drilling operations. Not only have deepwater activities been curtailed, but the political fallout has affected shallow-water activity as well. In many areas, the public is questioning the safety and environmental implications of hydraulic fracturing. The industry cannot ignore these questions. In the minds of many, “perception is reality,” and if the public is concerned, the industry must be concerned as well.

It is up to the industry to take a leadership position to address these issues. Waiting for the government to pass new, more stringent regulations could be disastrous. Leading pumping services companies have revealed the chemical compositions of their frac treatment fluids to forestall accusations of “black magic” from anti-industry activists. This is a step in the right direction, but more is needed.

At the same time, the public must be made aware of the strategic value of a strong energy industry to the safety and security of the nation. A knee-jerk reaction might have the effect of killing the goose that lays the golden egg. Both public safety and sustained hydrocarbon production can coexist – and they must until a better energy resource is identified, perfected, and commercialized.