Experts predict!

Emphasize reservoir characterization for long-term planning

By Mike Forrest, Consultant

The shale revolution in the US during the past decade was fast-moving. After initial geology studies and vertical well drilling with cores and testing, land acquisition was first priority. My old saying is, “An oil company can have a great exploration idea with state-of-the-art technical work, but without land holdings in the most attractive areas, the company has nothing.” The early movers usually acquired the most attractive acreage.

The land grab, sometimes at exorbitant prices that led to economic failures, was followed by acquiring additional geology data plus experiments in horizontal well landing points, lateral length, and hydraulic fracture and completion design. Microseismic surveys, either downhole or surface, were often acquired to get a general understanding of where the stimulated fractures were generated.

Today, most oil companies have drilled sufficient wells to hold key acreage. Drilling efficiencies including pad drilling – multiple horizontal wells from one surface location – have reduced costs. Infill programs are in progress. The massive amount of technical data in shale plays now needs to be reviewed with multidisciplinary teams integrating geological, geophysical, and engineering data to build reservoir characterization models, sometimes called earth models. Teamwork with geoscientists and engineers is essential.

The goals of these studies are to enhance the measurements to define commercial success. This includes initial production (IP) for gas and/or oil, decline rate measured over time as a well produces hydrocarbons, and estimated ultimate recovery (EUR) per well. There are uncertainties concerning all these criteria, including several definitions of IP, the fact that a small change in decline rate can be very important, and EUR estimates that increase or decrease over time. All technical disciplines – geology, geophysics, and engineering – are in the learning stage, even after several years of production history. In the end, the only meaningful criterion is the net income results over time.

Similar to conventional oil and gas field studies, the best results are obtained when the data are reviewed in their entirety with emphasis on the basics. For example, day-to-day interpretation of the data during the exploration and development stage can easily lead to bias that should be removed. This is similar to a conventional field redevelopment study that begins with recorrelating all of the electric logs and making new structure maps and net pay thickness maps. Also, an effort should be made to group all of the previous drilling experiences with best results, including geologic criteria; well landing point and drilled in zone; horizontal well length; and especially fracture stimulation design, which often varies considerably.

After more than 50 years as a geophysical interpreter, I believe the biggest reason for success is having a thorough knowledge of the technical data and the simple issues, the basics. In shale plays, the basics include understanding the rocks, source rock total organic carbon and relationship to nearby brittle intervals, porosity and pore throat size, and importance of selection of the horizontal well landing interval. Geoscience staff should work with drilling engineers on a 24-hour basis to keep horizontal wells in the selected zone.

A 1,525-m (5,000-ft) horizontal well will contact 50 times more rock than a 30-m (100-ft) interval in a vertical well, and complex stimulated fractures will contact several orders of magnitude more rock. Companies often state that hydraulic fracturing enables gas and oil to be produced at economic rates, but horizontal well drilling technology enables fracing to “touch” large volumes of the shale. Some studies indicate that most oil and gas is produced from a few hundred meters adjacent to the horizontal wellbore.

Hydraulic fracturing plays a major role in well productivity and thus must be included in reservoir characterization studies. This includes acquiring data to understand the stress field in the shale reservoir. Shales are strongly anisotropic, having significant rock property variations in all directions. Microseismic and 3-D seismic can help map velocity anisotropy, but there are data quality and resolution issues. In many cases, interpretation is in the learning stage. Understanding the role of natural fractures is also important as they can impact the stimulated fracture patterns.

The stress field in a shale changes during oil and gas production and can impact stimulated fracture patterns. There is evidence that some fractures close during pressure drawdown and this can be a factor in infill drilling programs where interference between wells can be an issue. Geoscientists and engineers map fractures on a relatively gross scale, and the details may never be fully understood.

Technology should play a major role in reservoir characterization studies. I believe the importance of porosity is undervalued, and discussions should include ways to improve mapping high-porosity areas and pore throat size. After understanding the detailed geologic framework and its variability, sometimes over short distances, discussions should include the application of 3-D seismic including multiple attributes to “fill in the white spaces” (the undrilled area) between wells. Some companies are using advanced microseismic data such as buried arrays over a large area to map fracture patterns over time.

Cost savings should be a deliverable from reservoir characterization studies. For example, can completion design be improved to select specific frac stages and perforation intervals? What is the optimum well spacing to drain oil and gas with the highest profitability?

A detailed reservoir characterization has many longterm advantages:

• Prioritizing and planning infill drilling programs;
• Increasing EUR per well by possibly as much as a factor of two;
• Assisting strategy for divesture and acquisition of assets via mergers or farm-ins; and
• Assisting in long-term financial planning.

Oil companies will drill thousands of wells in the shale plays during the next few years, and a long-term business and financial strategy should be based on integrated reservoir characterization studies.

FUD notwithstanding

By Dick Ghiselin, P.E., Qittitut Consulting

For decades our industry has progressed through technological innovation. One by one, the seemingly impassible hurdles of the E&P environment have been overcome through the combined efforts of operators and their technical services providers. Predicting the future with minimal success was simply a case of identifying the toughest problems of the day, which if solved yielded the highest return on investment – and you could bet that the industry would solve them.

But times have changed. No longer can we characterize our challenges solely in physical terms. Today we must consider geopolitics. An excellent example is the ill-fated Keystone pipeline project. Whether it ever carries a single drop of oil to Gulf Coast refineries has absolutely nothing to do with the terrain, the enabling technology, or the financial requirements. The decision is purely political.

Recent news revealed that the people of California have been unaware that hydraulic fracturing has been going on for decades there. Notwithstanding the fact that not one single frac-related incident of pollution, injury, or environmental damage has been attributed to the practice, activists have begun their attack. Using the press, they have started spreading fear, uncertainty, and doubt (FUD) among the populace. So if you asked me to predict the future production of California, I would have to consider the potential political effect of this story, an impossible task.

Overseas is no exception. Political forces have ruined the once-proud energy industry of Venezuela. At a Hart Energy-sponsored conference a decade ago, the president of Petr?leos de Venezuela SA (PDVSA) revealed his plan to boost production – then standing at about 3 MMb/d – to 6 MMb/d within the next five years. Then along came geopolitics. Where is Venezuelan production today?

In Russia, independent oil company Yukos bragged that it had doubled its production in two years while halving its inventory of wells – a remarkable feat of applied technology. But then politics came into the picture. The company was forced to sell its assets for a song, and it does not exist today.

The elephants in the room are China and India, whose thirst for energy grows unabated. Can anyone predict the political stability of these countries?

In the US, production has blossomed, and the country is becoming the world’s energy production hub. The vehicle that has enabled this phenomenal growth is technology. The vehicle that is on a crash course to curtail this growth is in Washington DC. The Keystone pipeline is but an example. Without a shred of evidence to support their claims, the anti-frac crowd accuses the industry of polluting freshwater aquifers and flooding wells with toxic chemicals. Notwithstanding the fact that we have been fracturing formations for more than half a century, the FUD persists, leading several states to ban hydraulic fracturing altogether.

Offshore the fallout from the Macondo incident is purely political. There is no denying that the Macondo incident was a tragedy. But the technological solution is at hand. The political effect of Macondo can be seen as some seek permission to explore the coastal areas of the Atlantic, Pacific, and Arctic oceans.

On to the crystal ball

Political possibilities aside, I predict a general shift of E&P overseas. This shift has already begun as evidenced by third-quarter results posted by the major service companies. With only modest gains in North America, these companies have booked record gains overseas. Despite the political turmoil in many key areas of the Middle East, others have managed to take up the slack. Off the east coast of Africa new discoveries promise to build industry interest in the area. The east coast of India beckons as well despite HP/HT issues. In fact, the current world record for deepwater drilling is held by Transocean’s Dhirubhai Deepwater KG-1 high-specification ultra-deepwater drillship in 3,174 m (10,411 ft) of water.

In the eastern Mediterranean, gas development offshore Israel continues apace, attracting the interest of Cyprus and Lebanon. These areas also hold promise of increased activity.

Australia continues to develop its gas reserves. Starting in Queensland, initiatives are proceeding to develop coalbed methane reserves and build pipelines to the southern population centers of the country. Shale gas development also is on the horizon. Offshore development continues to grow.

Deepwater offshore development of the Lower Tertiary play in the Gulf of Mexico holds high promise. Not only have several huge discoveries been announced in US waters, but it looks like Mexico will finally break its political logjam that has impeded its development of both land and deepwater areas. In my view Mexico holds the most exciting potential.

Technological innovations open doors

Although several technological innovations enhance the capabilities of service providers to enter deeper, hotter, higher pressure wells, one addresses a political concern. Many countries with attractive potential have very strict laws regarding importation and transportation of radioactive sources. This has inhibited formation evaluation, which depends on nuclear logging tool systems. Recently, Schlumberger introduced its NeoScope multifunction nuclear logging device, which does not require a chemical source. Because it generates its own radioactivity downhole using electronic generators, it is completely inert when deactivated. Accordingly, the tool can be easily imported and transported in countries with restrictive radioactivity laws. The tool has the potential to boost activity in those countries as they race to catch up in energy production.

Other technological innovations have aided the assault on HP/HT wells. Tool and battery technology improvements have addressed extreme temperatures in the Gulf of Thailand and in India’s Krishna Godivari basin. Of common concern are activities that require equipment to stay on bottom for extended periods. LWD systems are particularly susceptible to heat problems, and production logging permanent downhole gauges must be able to perform at temperature extremes for extended periods. Innovation is lagging behind demand in this area.

Although there is no question that hydrocarbons are a finite resource, the dire peak oil predictions of M. King Hubbert have been proved unfounded by technology improvements. I have complete confidence that technology will continue to win out over the technical barriers posed by the frontier environment. Thus, my prediction for the future is technically optimistic. Political optimism is another matter.

Artificial lift technologies will continue to evolve and converge

By Kevin Brady, Multi Products Co.

I was updating some training material a few weeks ago when I ran across a textbook on artificial lift that was published by the Petroleum Extension Service (PETEX) in 1985. Of the artificial lift methods it covered, sucker rod pumping was the most prevalent, it devoted just one seven-page chapter to gas lift and plunger lift, and plunger lift received only two pages. It also covered electric submersible pumps (ESPs) and hydraulic pumps. The instruction revolved around vertical wells, referred to directional wells as crooked holes, and didn’t reference horizontal drilling because the methodology was not yet widely adopted.

It doesn’t really seem like 1985 was that long ago, but we all know that a lot has changed with technology since that time. Technology has rapidly advanced in drilling and exploration but maybe not so much in the production aspects. At least that is how it appears in my mind. Maybe that is because exploration technology and drilling tools and methodologies are more exciting and receive more coverage in technical journals. But artificial lift technology has changed a lot too and is becoming more important as a focus on well economics and long-term productivity takes hold.

So where are we in the year 2013? Sucker rod pumping still comprises most of the artificial lift market – 82% of all wells, according to a recent report by Spears and Associates. ESPs comprise the largest spending segment, but that is declining as spending on rod pumping continues to grow. Other artificial lift methods have grown in popularity and acceptance as technologies have evolved.

Regarding plunger lift and gas lift technology, market information shows that the percentage of spend has remained about the same for the past few years. Maybe the rate of spending increase has not kept with the overall pace of artificial lift growth. But as I discuss this with operators, I find that they are considering more options when it comes to artificial lift selection, mainly due to technology improvements that are giving wells more overlap in application. In the past, a production engineer may have chosen to employ rod pumping without giving it much thought. Now that same production engineer may consider rod pumping, gas lift, plunger lift, gas-assisted plunger lift, velocity strings, or some other method before making a decision.

Plungers are asked to do much more than they were first designed to do, which was to extract small amounts of water from producing gas wells. Now plungers are operating in horizontal shale wells, sometimes down to 65° to 70° of inclination. These are being routinely employed in wells that are producing more than 100 b/d of oil and in wells that are producing more than 42 Mcm/d (1.5 MMcf/d) of natural gas.

Gas lift applications are also becoming more widely employed, especially in wells with lower gas-to-liquids ratios, where a lot of oil needs to be produced with not enough reservoir energy to move it. Gas lift has been the most widely employed method of artificial lift for mature offshore wells for some time. For horizontal shale wells and areas where operators have easy and economical access to a source of gas to inject along with compression to inject it, gas lift is a good solution. This method is being employed at a growing rate in producing wells in the Bakken, Eagle Ford, Utica, and other resource plays that produce high fluid volumes.

It used to be that production engineers that were installing plunger lift systems were running out of options. The well was getting near the end of its life, and it was producing less gas and more water. Economic analysis showed that a form of artificial lift with low capital cost and minimal operating costs was all that could be justified. If a newer well became a candidate for plunger lift, it was seen as a failure – a dog well, or one that the operator could not justify spending much money on. But that mindset is changing with horizontal shale wells. Just recently I was in a meeting with a production engineer who was happy to be installing plunger lift systems on wells that had been in production for a short time. His view was not that these were bad wells but that every well was going to need a form of artificial lift, and that for his program, plunger lift worked well. Not only was it an economical solution, it was producing the results he and his team were seeking. His view was, “I have a well that is producing 14 Mcm/d (500 Mcf/d) of gas and 120 b/d of oil, and plunger lift is helping me keep that production up. How can you call that a bad well?”

So as we sit here at the end of 2013, sucker rod pumping is still the most widely used form of artificial lift. But it is getting some strong competition from a list of alternatives that continue to emerge with lower capital costs, that fit an expanding range of well applications, and that produce results that production teams are happy with. If and when PETEX chooses to revise its artificial lift textbook, it will be interesting to see how the page count is divided up. My guess is that while rod pumping will still receive a healthy dose of pages, the allocation will be much more diversified among the alternatives.

The evolving work force in E&P

By Eve Sprunt, Consultant

FIGURE 1. A hiring hiatus in the '80s and '90s means that mid-career talent is now scarce. (Images courtesy of Eve Sprunt)

Students are flooding into petroleum engineering programs because they have seen those ahead of them get good starting offers at a time when few other industries have sustained their entry-level hiring. Overall there is not a shortage of entry-level talent, and competition has eased.

In some developing countries, there is a shortage of graduates who meet hiring standards. Upgrading university programs can be difficult because faculty members feel threatened by the proposed changes. Online courses combined with secure testing systems could provide a solution to identify qualified students. Just as mobile phones initially were more widely adopted in countries with unreliable phone systems, online courses combined with high-security testing may first gain traction in countries where the university programs are not accredited and internationally recognized.

With the double-decade-long oil price slump (Figure 1), mid-career talent is scarce. Competition for this talent segment will be intense. Companies have been trying to ease the shortage of mid-career employees with extensive training programs designed to minimize the number of years required to convert new hires into fully qualified professionals. The trick will be retaining the newly skilled professionals once the intensive training period ends.

The people hired in the heady days of the late 1970s/early 1980s oil boom are now over 50. Many of them plan to retire in the near future. If interest rates trend upward, long-term employees with interest rate-sensitive lump sum retirement benefits will be stampeding to the exits. A wealth of experience will vanish with them, but there are ways to keep retirees engaged and persuade them to return.

FIGURE 2. Younger men are much more likely to have a spouse who works full time. (Note: FT is employed full-time, PT is employed part-time, and "out" means left the work force.)

Retention of talent is a critical success metric, and the stakes are high with the “Big Crew Change.” Complicating the situation, the incoming work force differs in significant visible and invisible ways from the work force of the past. The 2013 SPE Talent Council retention survey found that prior to the Big Crew Change, the majority of the work force was composed of men who were their households’ single breadwinner (Figure 2). Younger men are increasingly likely to be “dual career” with a domestic partner who works full-time. Women are not only a growing fraction of the work force but are generally part of a dual-career couple (Figure 3). Attrition of mid-career women has been higher than for their male counterparts. Retention practices adopted in the last century were optimized for the male single-breadwinner work force and should be updated for the new work force that doesn’t have a stay-at-home partner managing domestic logistics.

Physicists refer to dual-career couples as the “two-body problem.” However challenging it is to find one good job, it is more difficult to find two attractive positions in the same area. When one partner is required to relocate, the couple faces sacrificing one career and income or repeating the process to find two positions together. Dual-career couples generally consider both careers to be equally important, and both men and women leave employers to follow a relocated partner. Some couples try to simplify the situation by working for the same employer, but others are not willing to accept the downside of that alternative, which is having their employer manage their careers as a couple.

“Conflict with supervisor/management” was a factor in retention of men in dual-career couples and women. The greater conflict may be because supervisors tend to be older and single breadwinners. These bosses may not understand the issues faced by dual-career couples and thus consider the employee’s choices to be unambitious and/or unprofessional. Companies with career development processes that continue to favor single breadwinners may end up with management who are increasingly out of touch with their work force and talent retention problems.

FIGURE 3. Women are a growing fraction of the work force and are generally part of a dual-career couple.

Inflexible work schedules, working too many hours, and too much time away from family were frequently cited by younger people as the most important reason they changed employers. Access to part-time work and telecommuting were not critical to most of the younger active work force but were among the strongest incentives to motivate people of all ages to return to the work force.

Opportunity is the most important driver for men and women of all ages. One of the top reasons women give for leaving the work force is “insufficient opportunity, challenge, career potential, and career stagnation.” Retirees and others who have left the work force can be motivated to return by “a chance to make a difference.” Younger people are relatively more motivated by opportunity than older people, so a younger work force will tend to be more likely to switch employers for what is perceived to be a good opportunity and a chance to develop new competencies.

In short, two areas require attention:

• Education and screening in developing countries; and
• Retention incentives for a work force that is rapidly changing.

References

Sprunt, Eve; Howes, Susan; and Pyrcz, Michael; 2013, Attraction and Retention of Employees, Results of 2013 SPE Talent Council Survey, SPE paper number 168112 (released Oct. 2, 2013).