With the continued shift from vertical to horizontal wells and from natural gas to oil and gas liquids, operators have been learning how to cost-efficiently complete wells to drain reservoirs and extend the productive life of those wells.

“The industry has done a great job of lowering drilling costs and getting wells drilled much faster and more efficiently. The focus now is on making the well completion phase more efficient and driving down those well completion costs by taking a hard look at the resources and equipment needed to complete these wells,” said Garrett Frazier, director of marketing and sales for Magnum Oil Tools.

Mark Hopmann, vice president of completions for Weatherford, asked,“What’s different about completions today than 10 years ago? Ten years ago we were more interested in completing the well to have a production conduit to the surface. Our focus today is completing a well to have discrete control of intervals in the formation. Because of that, you’ve seen a dramatic rise in the amount of money that our customers are spending on completions.

“If you go back and look at worldwide surveys of what was being spent on completions, in 2003 they were spending around [US] $3 billion a year worldwide on completions. In 2013 they are spending $9 billion or $10 billion on completions alone,” Hopmann said.“A lot of that increase is not related to the number of wells drilled; it is because we’re increasing the complexity of the completion itself to allow us to have that discrete compartmentalization.”

Domestic and international shale plays also are demanding new technology. “If we look at what the operators have been asking for over the last few years, they want to do more stages for less, have assurance that their fracs are going where they desire, and have confidence they are getting the ultimate recovery from their reservoir. Operators want to do more stages and inject their frac in the zone of interest while reducing risk and environmental impact. So how can we make this a repeatable process? How can I be a good steward of my environment? And [how do I] do all that while ensuring I have effectively stimulated my entire lateral?” asked Joe DeGeare, director of business development, NCS Energy Services.

“I think integration is going to be absolutely critical to drilling internationally because it is about problem-solving. And problems that you will find in basins outside the US are different than the problems we have in the Wolfcamp,” said Jeff Meisenhelder, vice president, unconventional resources, Schlumberger. “We are going to have to look – starting with geology and all the way through the completion and production process – at integrated solutions that will be the central focus in a specific way.”

E&P asked these and other industry experts to discuss technologies that are improving completions and the direction the industry is headed with cutting costs and increasing production.

Editor’s note: Many of the following comments were originally made at the DUG Permian Conference in Fort Worth, Texas, April 2 to 4, 2013.

Continuity with rigs, crews makes big difference

The rigs that make the most hole are the ones that have been in the area the longest.

By Mark Sundland, Anadarko Petroleum Corp.

Anadarko, through its acquisition of UPR, has horizontal drilling experience going back more than 20 years, developed primarily in the Austin Chalk and related plays. That has proven to be an advantage in the current portfolio. Only five years ago 10% of the wells we drilled were horizontal. Today it is 100% horizontal, and the efficiency gains have been astounding.

Five years ago we had 27 rigs and drilled about 3 million ft [915,000 m]. Last year we had 28 rigs – almost the exact same rig count – and drilled 7.5 million ft [2.3 million m]. And 2012 was phenomenal.

We try to minimize nonproductive time (NPT) so that we are on bottom drilling as much as possible. We view rig moving time as NPT, so with skid rigs drilling on pads, we keep moving time to a minimum. We are drilling wells twice as fast as competitors right across the lease line. Our 10-rig Eagle Ford program is making more footage than some companies’ 20-rig programs. A lot of that efficiency comes from pad drilling with these skid rigs, which are on the majority of our rigs in the Lower 48.

One observation I have made through benchmarking is that it is not all about technology. It is about how you run your business. At Anadarko we have the advantage of being well capitalized, allowing us to keep programs going year after year. We tend to keep the same drilling rigs going long-term, with the same crews, the same directional drillers, and the same company men. It is really the guys in the field who make the difference. That continuity is huge. There is a perfect correlation: The rigs that make the most hole are the ones that have been in the area the longest.

We see other operators who tend to pick up a rig, drop a rig, and get another rig. It just does not lead to continuity. Our focus on continuity helps the service companies know, “Okay, every six days we are going to be cementing for Anadarko.” You get into this rhythm, and it improves the efficiency of everything. If you are focused on continuity, you do not flip rigs up and down very much. We keep the rigs working, keep the crews together, and it works out best for everybody.

When we are talking about new technologies in completion and stimulation, we have to remember the influence of geology and the statistical nature of well results. When evaluating a particular method, you cannot just use the results from one or two wells. You have to talk about pilot programs for technology comparisons. You really need a side-by-side comparison of statistically significant samples rather than a single “best well” sample.

There is a lot of discussion around taking the shale plays to the international arena, but I think it is going to be difficult to translate what we are doing here overseas. What we have seen in the US is a perfect storm where you have got the right rigs, the right bit and motor combinations, and aggressive directional drillers who understand the nuances of horizontal drilling. The quality of your directional drillers will make or break you. The problem that I see with taking this technological success international is where are those directional drillers going to come from in Poland or Australia?

The demand for qualified people just in the Lower 48 is going to make it hard to transfer their expertise overseas. How are you going to get a directional driller from South Texas to say, “I want to spend my next hitch in Poland?” It will happen eventually, but it is not going to happen overnight.

We have seen so many tremendous efficiencies in rig designs and directional systems. We are always asking ourselves, “Where’s that next thing?” For example, we are looking at rig fuel alternatives. We have got three rigs running on bifuel using a mixture of diesel and our own field gas, and those are very promising. What we are finding, though, is that you have to have a certain substitution rate of natural gas vs. diesel to make it work. So a bifuel system may not always be the best answer, depending on your activity profile in a given play, so we are looking at all kinds of alternatives. Fuel management may sound small, but it is a pretty significant part of our cost. We look at everything, no matter how small, because it all adds up to big savings and more competitive economics in the long run.

Sliding-sleeve systems cut completion time, costs

Reducing well interventions lowers costs.

By Garrett Frazier, Magnum Oil Tools International

In the US shale plays well completion costs can account for upwards of 60% of the total cost associated to drill and complete a multistage horizontal well. The majority of the completion cost is devoted to the horsepower, proppant, and fluids needed to frac these wells. As the trend of increasing the number of frac stages per well continues, costs also are increasing.

Another significant cost in the well completion phase is the method of isolating the frac; i.e., plug and perf (PNP) or a ball-activated sliding-sleeve system. After the well has been fraced, well intervention is needed to remove the frac isolation method chosen and to clean up the well, which can be time-consuming and costly.

This year the estimated number of total US wells to be drilled and completed is approximately 47,000 to 50,000. About 72% of the rigs in the current US rig count are drilling horizontal wells. About 80% of the wells in the US shale plays will be completed with the PNP method, and the remaining 20% will use a ball-activated sliding-sleeve system method. There are pros and cons to these completion methods, and the debate is ongoing as to which is the best method in terms of total costs and total production.

Sliding-sleeve technology is going to play a significant role in the future of well completions, but there will always be a market for PNP. Depending on the geology, the formation can dictate which completion method is appropriate. From an operational perspective PNP might take five to seven days to complete a horizontal well barring any major problems, while a ball-activated sliding-sleeve system might take one to three days to complete the same number of total stages. So there is efficiency to be gained with the ball-activated sliding-sleeve system in regard to total well completion time.

There have been recent technological advances in cemented ball-activated sliding-sleeve systems. Halliburton, Peak Completions, and I-Tec all have a cemented sliding-sleeve system. The limits are being pushed with these cemented sliding-sleeve systems, yielding some encouraging results. Although the ball-activated sliding-sleeve system is more efficient with respect to time, the well intervention cleanout procedures can be time-consuming and costly.

The problem with this system is that frac balls made from composite material often get stuck on the ball seats during the frac. The stuck frac ball will not allow hydrocarbons from stages toward the toe of the horizontal well to flow to the surface; therefore, well intervention such as coiled tubing (CT) or a rig is needed to remove the stuck frac balls.

Magnum saw a need to develop a frac ball that can hold up to extreme frac pressures, will not get stuck, and will dissolve on its own to eliminate the need for the well intervention process. Magnum developed a frac ball that dissolves simply with well temperature called Magnum Fastball. There are no chemicals or special processes needed to make the Magnum Fastball dissolve.

This means the sliding-sleeve market now has available a dissolvable frac ball that will not impede production and could eliminate costly well intervention to drill out stuck frac balls. The ball shifts the sliding sleeve, holds up to the extreme frac pressures, and dissolves at a predictable rate as a function of well temperature after fracing.

The Magnum Smart Sleeve eliminates the need for tubing-conveyed perforating and is designed to open at predetermined applied surface pressure. Once the pressure is applied, the sleeve will open, allowing an acceptable injection rate into the formation. By using this technology, the E&P company can eliminate the tubing-conveyed perforating process. Depending on the cost of the CT unit or rig, this means savings to the E&P company of US $60,000 to $100,000 per horizontal well.

As the pace of domestic well completions races on, several E&P companies throughout the US shale plays are having trouble with compromised or failed casing. To address this problem, Magnum developed a frac plug for horizontal and vertical wells encountering casing restrictions such as casing patches, over-torqued collars, severe doglegs, and collapsed casing. The Magnum Long Range frac plug is a slim outer diameter, composite frac plug that can be conveyed to depth through these restrictions and set to isolate the portion of the well that needs to be perforated and fraced. To date, more than 100 wells once deemed not fit for completion have been revived by using this plug. Three Society of Petroleum Engineers (SPE) papers have been written on this technology: SPE 159751, SPE 146559, and CSUG/SPE 137839.

As expectations for domestic production continue to rise, so does the pressure for technology to help improve efficiencies all along the upstream energy value chain. These days, operators and service companies can no longer afford to apply yesterday’s technologies to the completion challenges of the future. What is the good news? Service companies are stepping up to invest in new completion technologies that promise better results for E&P companies – and more production, more quickly, for the economy as a whole.

Single-point injection reduces frac horsepower

A CT-deployed isolation assembly with a sliding sleeve allows each stage to be precisely placed.

By Joe DeGeare, NCS Energy Services

At the 2011 DUG Eagle Ford Conference in San Antonio, Texas, it was stated by a major operator that its goal was to increase the number of stages to accelerate production and enhance the ultimate recovery.

NCS offers a technology that combines a coiled tubing-(CT-) deployed isolation assembly with a sliding sleeve. With more than 20,000 sleeves that have been run in the past two years in wells that have reached 3.2 km (2 miles) in lateral length, we have a repeatable and reliable system. At each stage the resettable bridge plug is tested for integrity, and the sleeve shifts are positively identified with three separate signatures, including pressure, weight, and indicator sequence.

With single-point injection, surface rates, hydraulic horsepower, fuel consumption, emissions, noise levels, personnel, truck traffic, and pad size can be reduced while rates per initiation point remain the same or are increased, ensuring each stage is precisely placed. Stages can be added on the fly, and screenouts are reversed or avoided by monitoring dead string (real-time bottom-hole) pressure. The sleeves are full inner diameter with no ball seats, upsets, or plugs to remove). Operation time is similar or reduced due to the ability to circulate stimulation material, eliminate pump-down times, and eliminate rig up and rig down between stages with lubricators and explosives. When the last stage is treated operators are left with a production-ready wellbore with no restrictions and no milling operations. These features improve risk management and minimize environmental impact along with providing the most operational flexible system in the market.

For example, in an Eagle Ford completion, a frac is bullheaded down the casing. One might assume that a four-cluster stage pumping at 80 bbl/min would treat each cluster equally at 20 bbl/min. However, recent studies have shown that this is not the case. These studies have shown as little as one-third of clusters are actually contributing to production.

With the NCS Multistage Unlimited system, the annular frac would be designed for up to 35 bbl/min; thus, horsepower requirements are reduced by two-thirds. Operational time also is reduced compared to plug and perf jobs by eliminating the pumpdowns of composite plugs and shaped charges. Fluid requirements are decreased by eliminating the need to bullhead the treatment.

Also, by doing single-point injections, operators have the ability to enhance frac coverage and reduce the chances of communicating with neighboring wells. With the ability to monitor and record real-time bottom pressure and the usage of memory gauges below the tool assembly, they obtain greater information during and after the treatment and for future frac design in adjacent wells.

Regarding a recent Permian basin well, the operator said, “This system has the potential of letting us add one to two additional wells in our acreage due to the controlled frac.”

For new technology, we are looking at running fiber optics on some wells in Latin America. The use of fiber optics across our sleeves will give the operator the ability to monitor pressure and temperature during the frac and potentially for the life of the well. The goal of NCS Energy Services is to support the operator in improved estimated ultimate recovery through novel completion systems and to leave nothing behind.

Focus shifts from wellbore to reservoir completion

By dividing the reservoir into discrete intervals, the operator can individually stimulate each interval.

By Mark Hopmann, Weatherford

Iwould say in general what is happening in the completions industry right now is that our focus is changing from completing a wellbore to completing the reservoir itself. I think the major issues we hear from a lot of the operators are on the cost side. As the wells become more complex, they are worried about cost. We have to continue to work on the efficiency side to find ways to develop these things more quickly. We have to find ways to make the overall operation more economical for the customer.

What we are trying to do in this completion of the reservoir is divide it up into discrete intervals or compartments downhole. One focus of completing the well is to allow the operator to individually stimulate these compartments.

The second focus is to control the production from each of the wellbores or each of the compartments. If a horizontal section is divided up, individual flow is coming from various parts of the wellbore. How can that be controlled and homogenized? Inflow control devices can be used downhole and would allow operators to regulate the drawdown across the wellbore as well as delay the onset of water or gas production.

Let me divide the new technologies that Weatherford is pursuing into three categories. The first one would be offshore wells, our traditional completion-type equipment. One of the key technologies we are going forward with is radio frequency indentification (RFID) technology. The big focus for exploring this technology is being able to control the tools downhole without intervention. On a land well, the intervention cost is US $30,000 or $40,000 to get a coiled tubing unit. Offshore that cost goes up astronomically.

If we can find ways to complete all the work we need to do in the wellbore by simply dropping these RFID tags down, then that is the way new technology is going. We are running RFID to set packers and open valves to allow our customers to remotely plug the wellbore, circulate, and then remotely open and clean up the well. The big push here is efficiency and safety in the offshore environment.

The second focus would be on unconventional resources. We are continuing to expand our portfolio on sleeve-type systems for multizone fracturing and the openhole packers. The emphasis is to come out with technologies that eliminate the taper in the string. Operators are effectively limited on the number of zones they can have by the number of different ball seats they can fit into a particular geometry.

We are focused on what we call the i-ball stimulation sleeve. It is a single-ball solution that can open any number of sleeves with one size of ball. By eliminating string taper, we increase the number of zones up to virtually an infinite number. We reduce the amount of friction and therefore horsepower needed to pump the fluid downhole because everything is going through a larger diameter bore.

The third technology we are concentrating on is in the sand control arena. We are partnered with Exxon-Mobil to develop a technology for a self-mitigating sand screen. The trade name is MazeFlo. The tool is divided into compartments, each with an inner and outer screen. The theory is that if the outer screen member fails, the inner screen will take over, with increased inflow resistance. This increased resistance will cause the well to flow to other undamaged sections of the production horizon. We believe this can replace gravel packs as a long-term solution.

We are trying to increase the efficiency of land-based wells, particularly unconventional, by completing those wells to handle multiple forms of artificial lift. We run in the tubing string with a pump seating nipple integral to the string. Then we modify the lift technology to whatever is most appropriate for the stage the well is in. We would install a jet pump to enable flowback and then switch over to a gas-lift application during normal production. Finally, we would go back in with a reciprocating rod pump. Effectively, we can go through the entire life cycle of three different types of pumps with only one completion design.

In looking at some of the bigger problems yet to be solved, I think there is a big issue we have to work out technology-wise when we move into the Lower Tertiary play in the Gulf of Mexico, where deepwater and HP/HT issues are combined in the same well. We have operators talking to us now about 20,000-psi completion equipment. Combining that with something that is in 3,030 m (10,000 ft) of water and a 6,060-m (20,000-ft) well puts the operator 9,150 m (30,000 ft) deep in a wellbore. Trying to get accurate tool placement using traditional technology at these depths is a challenge.

Another huge problem in shale is determining where the frac is going. We perform fracture stimulations where we will pump a quarter of a million pounds of sand into a zone. We see operators trying to solve that issue either with tracers and microseismic or trying to find alternate ways to understand exactly what is happening with that rock when they are performing massive fracs.

Engineered completion designs boost effectiveness

There is a whole cornucopia of technologies that is available to aid in efficiency.

By Jeff Meisenhelder, Schlumberger

I think the real issue for completions is to get from being very efficient to being efficient and effective. We see that a high percentage – 25% or 35% – of perforation clusters do not produce. This is something that we know how to fix with engineered completion designs. By grouping completion stages and clusters according to reservoir quality and completion quality, we can get 100% of perforations producing. That makes everything more effective and drives cost per unit down. That is what I would say is the next step.

We are going to see more deployment of data acquisition tools that can help us with, first of all, completions engineering and better completion design. I do not think we are going to see the reinvention of full-blown LWD tools necessary for that purpose because people do not want to put costly tools into the laterals. We will see more nonintrusive technologies developed. There are ongoing trials using cuttings and much more sophisticated tools in mud logging to enable logging the well without ever putting tools into it. That is going to be a big step forward.

Coming back to unit cost, where I see a major potential gain is that we still drill a lot of wells that are not economic. That number could be 30%, 40%, or higher depending on the gas price. That leads to a huge opportunity in not drilling wells that are not economic. That will have a big impact on our unit cost and field economics. We are going to have to do that through a combination of technologies, integration, and developing new solutions.

We are going to have to use some tools that we have not used very much. For example, we can use seismic to help us find the spots that we do not want to drill. That is what we really need to know. There is a lot of room still for deeper integration of geology. And let’s face it: We do not fundamentally understand a lot of the principles of these kinds of reservoirs. We do not fundamentally understand oil transport in shales.

There is a lot of physics that still need to be done. As we develop that physics, we are going to get much more sophisticated about where we place wells, how we place them vertically, how we place them laterally, and how we complete them. That will be the next step change in performance. That is the big opportunity.

Regarding integration, it is not about a common software platform that has all the data in it. That, to me, is another efficiency tool. I think integration really is getting the team focused on specific problems and working those problems from each of their disciplines to reach a common solution.

When we talk about integration, we talk about activities at the well site and what I would call coordination, project management, logistics, or choreography. But real integration is about getting the team to solve a problem using all the disciplines to reinforce each other. If operators do that, they get a much better answer. It is a much more difficult task. It requires some of the tools that I just mentioned, but it really requires a good innovator, a strong team leader. And those skills, in the industry, are very scarce.

There is a whole cornucopia of technologies that are available to aid in efficiency. But really, it is the choreography at the well site that has brought all these things together and eliminated downtime, waiting on water time, waiting on diesel, or waiting on Schlumberger and brought it down to the most efficient use of everybody’s time for both the operators and the service companies. That, in turn, has driven prices down because everybody is using their assets at pretty much 100% capacity. In a sense, it is not just the technology; the project management aspect of it has been equally important.

Efficiency, effectiveness are key to completion success

Operators have to consider the value proposition of proposed technologies and of making the economics work.

Robin Robinson, Baker Hughes

The future of horizontal wells is in optimizing the fracturing and production that operators get as a result. A future development will be the tools that are around the drilling process that give us insight into the completion process – that can gather information in order to make decisions more quickly.

There also is a growing interest in sliding-sleeve technology. There will be more technologies involving dissolving completion components to improve efficiency. There have been significant advances in the longer laterals with the efficiencies that come from this technology. Also, pad drilling has been a game-changer, particularly in the southern basins where it is more developed and advanced.

With shale plays operators have to consider the value proposition of proposed technologies. It is all about making the economics work. The technologies that are used to develop the shale plays have to bring value. It is critical to the success of the project that the end results are increased production in less time while weighing the cost. For the most part, benchmarking always comes down to two issues: efficiency and effectiveness. One way to be more effective is for operators to share more production issues with service companies to develop better solutions; however, the public data available are at least six months old.

For efficiency one of the metrics we look at is how many wells are being drilled by each rig each quarter because it is a good indication of how efficiently we are working together. The Permian has seen a big improvement in the total number of wells drilled. From 2011 to 2012 there was a 70% increase in the number of horizontal wells, which is a great efficiency improvement since they are maintaining the same pace of wells drilled by each rig every quarter. We are seeing that the operators who have gained insight into the geology that they are working in are getting more into a well factory mode, which will bring even greater efficiencies.

The industry wants to know what we can do in the fracturing process to reduce the huge volumes of sand and water that are required. It is going to impact the Permian as well as international countries where we perform work. It is something that obviously needs a long-term solution. Additionally, identifying the most optimal location to perforate is still being developed.

Shared learning is paramount because there are some components that are common to all shale plays. There also are some that are basin-specific and some that are well-specific. Team leaders have to be careful not to inundate the organization with too much information.

One of the challenges is the organizational structure in many companies with separate drilling, completion, and production organizations. Information is not shared easily across these departments, and there are sometimes conflicting objectives.

When we look at these plays, what we see are more and more opportunities to cross those lines to take advantage of the growing information to place the bore in the sweet spot. Completion opportunities can be identified based on the information collected in the drilling process. Pulling together the service companies and the operators is going to be a key to advancing efficiencies. One of the solutions that we have been driven to in some areas is the idea of vertical integration, where on some limited scale we are supplying our own services. It is possible that these solutions also may be solutions for some international locations as well, although we are not yet 100% self-sufficient. We are still going to have to count on other support services following along and being there for operators to use.

As a service company, there are big challenges in performing equipment maintenance as soon as necessary due to the decrease in time from spud to total depth. It requires a huge investment from us, but we have been able to maintain equipment because we have decentralized facilities, allowing us to complete the work locally, and we have the necessary inventory to keep things running. Wells do not take as long now, and rig moves do not take as long, so our turn-around time is limited. But we are meeting the challenges to get those tools in for maintenance, into working condition, and back out to the well site.